Electrically Conductive Methods For Heating A Subsurface Formation To Convert Organic Matter Into Hydrocarbon Fluids

ABSTRACT

A method and system for heating a subsurface formation using electrical resistance heating is provided. In one aspect, two or more wellbores are provided that penetrate an interval of solid organic-rich rock within the subsurface formation. At least one fracture is established in the organic-rich rock from at least one of the wellbores, and electrically conductive material is provided in the fracture. In this way electrical communication is provided between the two or more wellbores. The electrically conductive material may include a first portion placed in contact with each of the two or more wellbores, and a second portion intermediate the two or more wellbores. The first portion has a first bulk resistivity while the second portion has a second bulk resistivity. The method also includes passing electric current through the fracture such that heat is generated by electrical resistivity within the electrically conductive material sufficient to pyrolyze at least a portion of the organic-rich rock into hydrocarbon fluids. The resistive heat generated within the first portion of the electrically conductive material is less than the heat generated within the second portion of the electrically conductive material.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional PatentApplication 61/109,369 filed 29 Oct. 2008 entitled ELECTRICALLYCONDUCTIVE METHODS FOR HEATING A SUBSURFACE FORMATION TO CONVERT ORGANICMATTER INTO HYDROCARBON FLUIDS, the entirety of which is incorporated byreference herein. This application claims the benefit of pending U.S.non-provisional patent application Ser. No. 12/074,899, attorney DocketNumber 2007EM026, which was filed on Mar. 7, 2008 and which is entitled“Granular Electrical Connections for In Situ Formation Heating” and isincorporated herein in its entirety by reference. U.S. application Ser.No. 12/074,899 in turn claims the benefit of pending U.S. provisionalpatent Application No. 60/919,391, which was filed on Mar. 22, 2007,which is also entitled “Granular Electrical Connections for In SituFormation Heating,” and is incorporated herein in its entirety byreference.

BACKGROUND

1. Technical Field

The present invention relates to the field of hydrocarbon recovery fromsubsurface formations. More specifically, the present invention relatesto the in situ recovery of hydrocarbon fluids from organic-rich rockformations including, for example, oil shale formations, coal formationsand tar sands formations. The present invention also relates to methodsfor heating a subsurface formation using electrical energy.

2. Discussion of Technology

Certain geological formations are known to contain an organic matterknown as “kerogen.” Kerogen is a solid, carbonaceous material. Whenkerogen is imbedded in rock formations, the mixture is referred to asoil shale. This is true whether or not the mineral is, in fact,technically shale, that is, a rock formed from compacted clay.

Kerogen is subject to decomposing upon exposure to heat over a period oftime. Upon heating, kerogen molecularly decomposes to produce oil, gas,and carbonaceous coke. Small amounts of water may also be generated. Theoil, gas and water fluids become mobile within the rock matrix, whilethe carbonaceous coke remains essentially immobile.

Oil shale formations are found in various areas world-wide, includingthe United States. Such formations are notably found in Wyoming,Colorado, and Utah. Oil shale formations tend to reside at relativelyshallow depths and are often characterized by limited permeability. Someconsider oil shale formations to be hydrocarbon deposits which have notyet experienced the years of heat and pressure thought to be required tocreate conventional oil and gas reserves.

The decomposition rate of kerogen to produce mobile hydrocarbons istemperature dependent. Temperatures generally in excess of 270° C. (518°F.) over the course of many months may be required for substantialconversion. At higher temperatures substantial conversion may occurwithin shorter times. When kerogen is heated to the necessarytemperature, chemical reactions break the larger molecules forming thesolid kerogen into smaller molecules of oil and gas. The thermalconversion process is referred to as pyrolysis or retorting.

Attempts have been made for many years to extract oil from oil shaleformations. Near-surface oil shales have been mined and retorted at thesurface for over a century. In 1862, James Young began processingScottish oil shales. The industry lasted for about 100 years. Commercialoil shale retorting through surface mining has been conducted in othercountries as well. Such countries include Australia, Brazil, China,Estonia, France, Russia, South Africa, Spain, and Sweden. However, thepractice has been mostly discontinued in recent years because it hasproven to be uneconomical or because of environmental constraints onspent shale disposal. (See T. F. Yen, and G. V. Chilingarian, “OilShale,” Amsterdam, Elsevier, p. 292, the entire disclosure of which isincorporated herein by reference.) Further, surface retorting requiresmining of the oil shale, which limits that particular application tovery shallow formations.

In the United States, the existence of oil shale deposits innorthwestern Colorado has been known since the early 1900's. Whileresearch projects have been conducted in this area from time to time, noserious commercial development has been undertaken. Most research on oilshale production has been carried out in the latter half of the 1900's.The majority of this research was on shale oil geology, geochemistry,and retorting in surface facilities.

In 1947, U.S. Pat. No. 2,732,195 issued to Ljungstrom. That patent,entitled “Method of Treating Oil Shale and Recovery of Oil and OtherMineral Products Therefrom,” proposed the application of heat at hightemperatures to the oil shale formation in situ. The purpose of such insitu heating was to distill hydrocarbons and produce them to thesurface. The '195 Ljungstrom patent is incorporated herein by reference.

Ljungstrom coined the phrase “heat supply channels” to describe boreholes drilled into the formation. The bore holes received an electricalheat conductor which transferred heat to the surrounding oil shale.Thus, the heat supply channels served as early heat injection wells. Theelectrical heating elements in the heat injection wells were placedwithin sand or cement or other heat-conductive material to permit theheat injection wells to transmit heat into the surrounding oil shalewhile preventing the inflow of fluid. According to Ljungstrom, the“aggregate” was heated to between 500° and 1,000° C. in someapplications.

Along with the heat injection wells, fluid producing wells were alsocompleted in near proximity to the heat injection wells. As kerogen waspyrolyzed upon heat conduction into the rock matrix, the resulting oiland gas would be recovered through the adjacent producing wells.

Ljungstrom applied his approach of thermal conduction from heatedwellbores through the Swedish Shale Oil Company. A full scale plant wasdeveloped that operated from 1944 into the 1950's. (See G. Salamonsson,“The Ljungstrom In Situ Method for Shale-Oil Recovery,” 2^(nd) Oil Shaleand Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute ofPetroleum, London, p. 260-280 (1951), the entire disclosure of which isincorporated herein by reference.)

Additional in situ methods have been proposed. These methods generallyinvolve the injection of heat and/or solvent into a subsurface oil shaleformation. Heat may be in the form of heated methane (see U.S. Pat. No.3,241,611 to J. L. Dougan), flue gas, or superheated steam (see U.S.Pat. No. 3,400,762 to D. W. Peacock). Heat may also be in the form ofelectric resistive heating, dielectric heating, radio frequency (RF)heating (U.S. Pat. No. 4,140,180, assigned to the ITT Research Institutein Chicago, Ill.) or oxidant injection to support in situ combustion. Insome instances, artificial permeability has been created in the matrixto aid the movement of pyrolyzed fluids. Permeability generation methodsinclude mining, rubblization, hydraulic fracturing (see U.S. Pat. No.3,468,376 to M. L. Slusser and U.S. Pat. No. 3,513,914 to J. V. Vogel),explosive fracturing (see U.S. Pat. No. 1,422,204 to W. W. Hoover, etal.), heat fracturing (see U.S. Pat. No. 3,284,281 to R. W. Thomas), andsteam fracturing (see U.S. Pat. No. 2,952,450 to H. Purre).

In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil Company, the entiredisclosure of which is incorporated herein by reference. That patent,entitled “Conductively Heating a Subterranean Oil Shale to CreatePermeability and Subsequently Produce Oil,” declared that “[c]ontrary tothe implications of . . . prior teachings and beliefs . . . thepresently described conductive heating process is economically feasiblefor use even in a substantially impermeable subterranean oil shale.”(col. 6, ln. 50-54). Despite this declaration, it is noted that few, ifany, commercial in situ shale oil operations have occurred other thanLjungstrom's enterprise. The '118 patent proposed controlling the rateof heat conduction within the rock surrounding each heat injection wellto provide a uniform heat front.

As indicated above, resistive heating techniques for a subsurfaceformation have been considered. F. S. Chute and F. E. Vermeulen, Presentand Potential Applications of Electromagnetic Heating in the In SituRecovery of Oil, AOSTRA J. Res., v. 4, p. 19-33 (1988) describes aheavy-oil pilot test where “electric preheat” was used to flow electriccurrent between two wells to lower viscosity and create communicationchannels between wells for follow-up with a steam flood. It has beendisclosed to run alternating current or radio frequency electricalenergy between stacked conductive fractures or electrodes in the samewell in order to heat a subterranean formation. See U.S. Pat. No.3,149,672 titled “Method and Apparatus for Electrical Heating ofOil-Bearing Formations;” U.S. Pat. No. 3,620,300 titled “Method andApparatus for Electrically Heating a Subsurface Formation;” U.S. Pat.No. 4,401,162 titled “In Situ Oil Shale Process;” and U.S. Pat. No.4,705,108 titled “Method for In Situ Heating of HydrocarbonaceousFormations.” U.S. Pat. No. 3,642,066 titled “Electrical Method andApparatus for the Recovery of Oil,” provides a description of resistiveheating within a subterranean formation by running alternating currentbetween different wells. Others have described methods to create aneffective electrode in a wellbore. See U.S. Pat. No. 4,567,945 titled“Electrode Well Method and Apparatus;” and U.S. Pat. No. 5,620,049titled “Method for Increasing the Production of Petroleum From aSubterranean Formation Penetrated by a Wellbore.” U.S. Pat. No.3,137,347 titled “In Situ Electrolinking of Oil Shale,” describes amethod by which electric current is flowed through a fracture connectingtwo wells to get electric flow started in the bulk of the surroundingformation. Heating of the formation occurs primarily due to the bulkelectrical resistance of the formation.

Additional history behind oil shale retorting and shale oil recovery canbe found in co-owned U.S. Pat. No. 7,331,385 entitled “Methods ofTreating a Subterranean Formation to Convert Organic Matter intoProducible Hydrocarbons.” The Background and technical disclosure ofthis patent is incorporated herein by reference.

A need exists for improved processes for the production of shale oil. Inaddition, a need exists for improved methods for heating a subsurfaceformation. Still further, a need exists for methods that facilitate anexpeditious and effective subsurface heater well arrangement using anelectrically conductive granular material placed within an organic-richrock formation.

SUMMARY

In one embodiment, a method for heating a subsurface formation usingelectrical resistance heating is provided. In one aspect, the methodincludes providing two or more wellbores that penetrate an interval ofsolid organic-rich rock within the subsurface formation. Preferably, theorganic-rich rock comprises oil shale.

At least one fracture is established in the organic-rich rock from atleast one of the two or more wellbores. Preferably, the at least onefracture is formed hydraulically. The method also includes placingelectrically conductive material in the at least one fracture. In thisway electrical communication is provided between the two or morewellbores. The electrically conductive material comprises first portionsplaced in contact with each of the two or more wellbores, and a secondportion intermediate the first portions and around the two or morewellbores. The first portions have a first bulk resistivity while thesecond portion has a second bulk resistivity.

The method also includes passing electric current through the fracturesuch that heat is generated by electrical resistivity within theelectrically conductive material sufficient to pyrolyze at least aportion of the organic-rich rock into hydrocarbon fluids. The heatgenerated within the first portions of the electrically conductivematerial is less than the heat generated within the second portion ofthe electrically conductive material.

In one embodiment, each of the two or more wellbores is completedsubstantially vertically, and the at least one fracture is substantiallyhorizontal. In another embodiment, each of the two or more wellbores iscompleted substantially horizontally, and the at least one fracture issubstantially vertical.

The electrically conductive material preferably comprises a proppantmaterial. In one aspect, the first portions of the electricallyconductive material comprise granular metal, metal coated particles,coke, graphite, or combinations thereof. In another aspect, the secondportion of the electrically conductive material comprises granularmetal, metal coated particles, coke, graphite, or combinations thereof.

As noted, the resistivity of the first portions is different than in thesecond portion. In one aspect, the resistivity of the materialcomprising the second portion of the electrically conductive material isabout 10 to 100 times greater than the resistivity of the materialcomprising the first portions of the electrically conductive material.In one example, and by way of example only, the resistivity of the firstportions of the electrically conductive material may be about 0.005Ohm-meters. Alternatively, the resistivities of the first portions maybe about 0.00005 Ohm-meters, or even as low as 0.00001 Ohm-Meters.

In another aspect, the first portions of the electrically conductivematerial are substantially non-conductive, and the second portion of theelectrically conductive material contacts at least a portion of each ofthe two or more wellbores. Examples of non-conductive materials includesilica, quartz, cement chips, sandstone, or combinations thereof. In oneexample, and by way of example only, the resistivity of the firstportions of the electrically conductive material approaches infinity.

In one embodiment, the method also includes the step of continuing topass electrical current through the first and second conductive portionsof electrically conductive material. In this way pyrolysis of oil shaleinto hydrocarbon fluids occurs. The hydrocarbon fluids may then beproduced from the subsurface formation to a surface processing facility.

Another method for heating a subsurface formation using electricalresistance heating is provided herein. Preferably, the subsurfaceformation is an organic-rich rock formation. Preferably, the subsurfaceformation contains heavy hydrocarbons. More preferably, the subsurfaceformation is an oil shale formation.

The method includes creating at least one passage in the subsurfaceformation between a first wellbore located at least partially within thesubsurface formation and a second wellbore also located at leastpartially within the subsurface formation. An electrically conductivematerial is placed into the at least one passage to form an electricalconnection. The electrical connection provides electrical communicationbetween the first wellbore and the second wellbore. The electricallyconductive material may be a granular material.

The method also includes providing a first electrically conductivemember in the first wellbore so that the first electrically conductivemember is in electrical communication with the electrical connection,and providing a second electrically conductive member in the secondwellbore so that the second electrically conductive member is also inelectrical communication with the electrical connection. In this way, anelectrically conductive flow path comprised at least of the firstelectrically conductive member, the electrical connection and the secondelectrically conductive member is formed.

The method also includes establishing an electrical current through theelectrically conductive flow path. This generates heat within theelectrically conductive flow path due to electrical resistive heating.At least a portion of the generated heat thermally conducts into thesubsurface formation. In accordance with this method, the generated heatis comprised of first heat generated in proximity to the firstelectrically conductive member and the second electrically conductivemember, and second heat generated from the electrically conductivematerial intermediate the first electrically conductive member and thesecond electrically conductive member. The first heat is less than thesecond heat. Preferably, the generated heat causes pyrolysis of solidhydrocarbons within at least a portion of the subsurface formation.

In one embodiment, the electrically conductive material comprises (i)first portions in immediate proximity to the first electricallyconductive member and the second electrically conductive member,respectively, and (ii) a second portion intermediate the first portionsaround the first and second electrically conductive members. Aresistivity of the first portion is different than a resistivity of thesecond portion. In one aspect, the first portions of the electricallyconductive material have a sufficiently low electrical resistivity so asto provide electrical conduction without substantial heat generation.

For example, the first portions of the electrically conductive granularmaterial may include less than or equal to 50 percent by dry weight ofcement and 50 percent or more by dry weight of graphite. The firstportions of the electrically conductive granular material may includebetween 50 to 75 percent of granular metal, metal coated particles,coke, graphite, or combinations thereof.

In one general aspect, a method for heating a subsurface formation usingelectrical resistance heating includes providing two or more wellboresthat penetrate an interval of solid organic-rich rock within thesubsurface formation; establishing at least one fracture in theorganic-rich rock from at least one of the two or more wellbores; andproviding electrically conductive material in the at least one fractureso as to provide electrical communication between the two or morewellbores. The electrically conductive material includes (i) firstportions placed in contact with each of the two or more wellbores andhaving a first bulk resistivity, and (ii) a second electricallyconductive portion intermediate the two or more wellbores and having asecond bulk resistivity. Electric current is passed through the at leastone fracture such that resistive heat is generated within theelectrically conductive material sufficient to pyrolyze at least aportion of the organic-rich rock into hydrocarbon fluids, wherein thegenerated heat is lower within the first portions of the electricallyconductive material than in the second portion of the electricallyconductive material.

Implementations of this aspect may include one or more of the followingfeatures. For example, the organic-rich rock may include oil shale. Eachof the two or more wellbores may be completed substantially verticallyand/or horizontally. The at least one fracture may be substantiallyhorizontal, vertical, or some combination thereof. The electricallyconductive material may include a granular material that serves as aproppant. The first portions of the electrically conductive material mayinclude granular metal, metal coated particles, coke, graphite, and/orany combination thereof. The second portion of the electricallyconductive material may include granular metal, metal coated particles,coke, graphite, and/or any combination thereof. The resistivity of thematerial comprising the second portion of the electrically conductivematerial may be about 10 to 100 times greater than the resistivity ofthe material comprising the first portions of the electricallyconductive material. The first portions of the electrically conductivematerial may be substantially non-conductive. The second portion of theelectrically conductive material may contact at least a portion of eachof the two or more wellbores. The first portions of the electricallyconductive material may include silica, quartz, cement chips, sandstone,and/or any combination thereof. The resistivity of the first portions ofthe electrically conductive material may be about 0.005 Ohm-Meters. Theresistivity of the first portions of the electrically conductivematerial may be between about 0.00001 Ohm-Meters and 0.00005 Ohm-Meters.The resistivity of the first portions of the electrically conductivematerial may approach infinity. The at least one fracture may be formedhydraulically. Electrical current may be continually or intermittentlypassed through the first and second portions of electrically conductivematerial so as to cause pyrolysis of oil shale into hydrocarbon fluids.Hydrocarbon fluids may be produced from the subsurface formation to asurface processing facility, e.g., with one or more production wells.

In another general aspect, a method for heating a subsurface formationusing electrical resistance heating includes creating at least onepassage in the subsurface formation between a first wellbore located atleast partially within the subsurface formation and a second wellborealso located at least partially within the subsurface formation. Anelectrically conductive material is provided into the at least onepassage to form an electrical connection, the electrical connectionproviding electrical communication between the first wellbore and thesecond wellbore. A first electrically conductive member is provided inthe first wellbore so that the first electrically conductive member isin electrical communication with the electrical connection. A secondelectrically conductive member is provided in the second wellbore, sothat the second electrically conductive member is in electricalcommunication with the electrical connection, thereby forming anelectrically conductive flow path comprised at least of the firstelectrically conductive member, the electrical connection and the secondelectrically conductive member. An electrical current may be establishedthrough the electrically conductive flow path, thereby generating heatwithin the electrically conductive flow path due to electrical resistiveheating, with at least a portion of the generated heat thermallyconducting into the subsurface formation, and wherein the generated heatis comprised of first heat generated in proximity to the firstelectrically conductive member and the second electrically conductivemember, and second heat generated from the electrically conductivegranular material intermediate the first electrically conductive memberand the second electrically conductive member, with the first heat beingless than the second heat.

Implementations of this aspect may include one or more of the followingfeatures. For example, the subsurface formation may be an organic-richrock formation. The subsurface formation may contain heavy hydrocarbons.The subsurface formation may be an oil shale formation. The electricallyconductive material may include a granular material. The electricalconnection may include a granular electrical connection. The generatedheat causes pyrolysis of solid hydrocarbons within at least a portion ofthe subsurface formation. The electrically conductive granular materialmay include (i) first portions in immediate proximity to the firstelectrically conductive member and the second electrically conductivemember, respectively, and (ii) a second portion intermediate the firstportions around the first and second electrically conductive members.The resistivity of the first portions may be different than aresistivity of the second portion. The first portions of theelectrically conductive granular material may have a sufficiently lowelectrical resistivity so as to provide electrical conduction withoutsubstantial heat generation. The first portions of the electricallyconductive granular material may include granular metal, metal coatedparticles, coke, graphite, and/or any combination thereof. The secondportion of the electrically conductive granular material may includegranular metal, metal coated particles, coke, graphite, and/or anycombination thereof. The resistivity of the material comprising thesecond portion of the electrically conductive granular material may beabout 10 to 100 times greater than the resistivity of the materialcomprising the first portions of the electrically conductive granularmaterial. The first portions of the electrically conductive granularmaterial may include less than or equal to 50 percent by dry weight ofcement and 50 percent or more by dry weight of graphite. The firstportions of the electrically conductive granular material may includebetween 50 to 75 percent of granular metal, metal coated particles,coke, graphite, and/or any combination thereof. The first portions ofthe electrically conductive granular material may be substantiallynon-conductive; and the second portion of the electrically conductivegranular material contacts at least a portion of each of the first andsecond electrically conductive members. The first portions of theelectrically conductive granular material may include silica, quartz,cement chips, sandstone, and/or any combination thereof. The resistivityof the first portions of the electrically conductive granular materialmay be about 0.005 Ohm-meters. The resistivity of the first portions ofthe electrically conductive material may approach infinity. The firstwellbore and the second wellbore may each be completed substantiallyvertically; and the passage in the subsurface formation may include asubstantially vertically fracture. The first wellbore and the secondwellbore may each be completed substantially horizontally; and the atleast one passage in the subsurface formation may include a firstsubstantially vertical fracture. A third electrically conductive membermay be provided in a third wellbore, such that the third electricallyconductive member is also in electrical communication with theelectrical connection and is part of the electrically conductive flowpath. The third wellbore may be completed substantially horizontally.The at least one passage in the subsurface formation may include asecond substantially vertical fracture. The second wellbore mayintersect both the first fracture and the second fracture. The materialcomprising at least a portion of the first electrically conductivemember, the second electrically conductive member, or both may have anelectrical resistivity of less than 0.0005 Ohm-meters. An electricalcurrent may be continually or intermittently passed through theelectrical connection until the subsurface formation immediatelyadjacent the electrically conductive flow path reaches a selectedtemperature; and reducing an amount of current through the electricalconnection.

In another general aspect, a system for in situ heating of a subsurfaceformation using electrical resistance heating includes a plurality ofwellbores that penetrate an interval of solid organic-rich rock withinthe subsurface formation. At least one fracture in the organic-rich rockis established from at least one of the wellbores, wherein the at leastone fracture includes electrically conductive material to provideelectrical communication between at least two of the wellbores. Theelectrically conductive material may include (i) first portions placedin contact with at least two wellbores and having a first bulkresistivity, and (ii) a second electrically conductive portionintermediate the at least two wellbores and having a second bulkresistivity. At least one electrical conductor is operatively connectedto the first portions of the electrically conductive material in each ofthe at least two wellbores, the at least one electrical conductor beingconfigured to pass electric current through the at least one fracturesuch that resistive heat is generated within the electrically conductivematerial sufficient to pyrolyze at least a portion of the organic-richrock into hydrocarbon fluids. The generated heat may be lower within thefirst portions of the electrically conductive material than in thesecond portion of the electrically conductive material.

Implementations of this aspect may include one or more of the followingfeatures. For example, each of the two or more wellbores may becompleted substantially vertically, horizontally, or some combinationthereof. The at least one fracture may be substantially horizontal,vertical, or some combination thereof. The electrically conductivematerial may include a granular material that serves as a proppant. Thefirst portions of the electrically conductive material may includegranular metal, metal coated particles, coke, graphite, and/or anycombination thereof. The second portion of the electrically conductivematerial may include granular metal, metal coated particles, coke,graphite, and/or any combination thereof. The resistivity of thematerial comprising the second portion of the electrically conductivematerial may be about 10 to 100 times greater than the resistivity ofthe material comprising the first portions of the electricallyconductive material. The first portions of the electrically conductivematerial may be substantially non-conductive. The second portion of theelectrically conductive material may contact at least a portion of eachof the two or more wellbores. The first portions of the electricallyconductive material may include silica, quartz, cement chips, sandstone,and/or any combination thereof. The resistivity of the first portions ofthe electrically conductive material may be about 0.005 Ohm-Meters. Theresistivity of the first portions of the electrically conductivematerial may be between about 0.00001 Ohm-Meters and 0.00005 Ohm-Meters.The resistivity of the first portions of the electrically conductivematerial may approach infinity. The at least one fracture may be formedhydraulically. The system may include one or more production wells forproducing hydrocarbon fluids from the subsurface formation.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present invention can be better understood, certaindrawings, charts, graphs and flow charts are appended hereto. It is tobe noted, however, that the drawings illustrate only selectedembodiments of the inventions and are therefore not to be consideredlimiting of scope, for the inventions may admit to other equallyeffective embodiments and applications.

FIG. 1 is a cross-sectional isometric view of an illustrative subsurfacearea. The subsurface area includes an organic-rich rock matrix thatdefines a subsurface formation.

FIG. 2 is a flow chart demonstrating a general method of in situ thermalrecovery of oil and gas from an organic-rich rock formation, in oneembodiment.

FIG. 3 is a cross-sectional side view of an illustrative oil shaleformation that is within or connected to groundwater aquifers, and aformation leaching operation.

FIG. 4 is a plan view of an illustrative heater well pattern. Two layersof heater wells are shown around respective production wells.

FIG. 5 is a bar chart comparing one ton of Green River oil shale beforeand after a simulated in situ, retorting process.

FIG. 6 is a process flow diagram of exemplary surface processingfacilities for a subsurface formation development.

FIG. 7 is a perspective view of a hydrocarbon development area. Asubsurface formation is being heated via resistive heating. A mass ofconductive granular material has been injected into the formationbetween two adjacent wellbores.

FIG. 8A is a perspective view of another hydrocarbon development area. Asubsurface formation is once again being heated via resistive heating. Amass of conductive granular material has been injected into theformation from a plurality of horizontally completed wellbores.Corresponding wellbores are completed horizontally through theindividual masses of conductive granular material.

FIG. 8B is yet another perspective view of a hydrocarbon developmentarea. A subsurface formation is once again being heated via resistiveheating. A mass of conductive granular material has been injected intothe formation from a pair of horizontally completed wellbores. A thirdwellbore is completed horizontally through the masses of conductivegranular material.

FIG. 9 is a perspective view of a core sample that has been opened alongits longitudinal axis. Steel shot has been placed within a “tray” formedinternal to the core sample.

FIG. 10 shows the core sample of FIG. 9 having been closed and clampedfor testing. A current is run through the length of the core sample tocreate resistive heating.

FIG. 11 provides a series of charts wherein power, temperature andresistance are measured as a function of time during the heating of thecore sample of FIG. 9.

FIG. 12 demonstrates a flow of current through a geologic formation thathas been fractured. Arrows demonstrate current increments in the x and ydirections for partial derivative equations.

FIG. 13 is a thickness-conductivity map showing a plan view of asimulated fracture. Two steel plates are positioned within surroundingconductive granular proppant within the fracture. The map is gray-scaledto show the product value of conductivity multiplied by the thickness ofthe conductive granular proppant across the fracture.

FIG. 14 is another view of the thickness-conductivity map of FIG. 13.The map is gray-scaled in finer increments of conductivity multiplied bythickness to distinguish variations in proppant thickness.

FIG. 15 is a representation of electric current moving into and out ofthe fracture plane of FIG. 13. This representation is an electriccurrent source map.

FIG. 16 shows a voltage distribution within the fracture of FIG. 13.

FIG. 17 shows a heating distribution within the fracture of FIG. 13.

FIG. 18 is a thickness-conductivity map showing a plan view of asimulated fracture plane. Two steel plates are again positioned withinsurrounding conductive granular proppants within the fracture plane. Themap is gray-scaled to show the product value of conductivity multipliedby the thickness of the conductive granular proppants across thefracture.

FIG. 19 is another view of the thickness-conductivity map of FIG. 18.The map is gray-scaled in finer increments of conductivity multiplied bythickness to distinguish product values between the calcined coke,around the steel plates and a higher conductivity proppant, or“connector.”

FIG. 20 is another view of the thickness-conductivity map of FIG. 18.The map is gray-scaled in still further finer increments of conductivitytimes thickness to distinguish variations in conductivity between thecalcined coke around the steel plates and the higher conductivityproppant.

FIG. 21 is a representation of electric current moving into and out ofthe fracture plane of FIG. 18. This representation is an electriccurrent source map.

FIG. 22 shows a voltage distribution within the fracture plane of FIG.18.

FIG. 23 shows a heating distribution within the fracture plane of FIG.18.

FIG. 24 is a thickness-conductivity map showing a plan view of asimulated fracture plane. Two steel plates are again positioned withinsurrounding conductive granular proppants within the fracture plane. Themap is gray-scaled to show the product value of conductivity multipliedby thickness for the conductive granular proppants across the fracture.

FIG. 25 is another view of the thickness-conductivity map of FIG. 24.The map is gray-scaled in finer increments of conductivity multiplied bythickness to distinguish between calcined coke, or “connector,” aroundthe steel plates and a higher conductivity proppant.

FIG. 26 is a representation of electric current moving into and out ofthe fracture plane of FIG. 24. This representation is an electriccurrent source map.

FIG. 27 shows a voltage distribution within the fracture plane of FIG.24.

FIG. 28 shows a heating distribution within the fracture plane of FIG.24.

DETAILED DESCRIPTION Definitions

As used herein, the term “hydrocarbon(s)” refers to organic materialwith molecular structures containing carbon bonded to hydrogen.Hydrocarbons may also include other elements such as, but not limitedto, halogens, metallic elements, nitrogen, oxygen, and/or sulfur.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon ormixtures of hydrocarbons that are gases or liquids. For example,hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbonsthat are gases or liquids at formation conditions, at processingconditions or at ambient conditions (15° C. and 1 atm pressure).Hydrocarbon fluids may include, for example, oil, natural gas, coal bedmethane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product ofcoal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the terms “produced fluids” and “production fluids”refer to liquids and/or gases removed from a subsurface formation,including, for example, an organic-rich rock formation. Productionfluids may include, but are not limited to, pyrolyzed shale oil,synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogensulfide and water (including steam). Produced fluids may include bothhydrocarbon fluids and non-hydrocarbon fluids.

As used herein, the term “condensable hydrocarbons” means thosehydrocarbons that condense at 25° C. and one atmosphere absolutepressure. Condensable hydrocarbons may include a mixture of hydrocarbonshaving carbon numbers greater than 4.

As used herein, the term “non-condensable hydrocarbons” means thosehydrocarbons that do not condense at 25° C. and one atmosphere absolutepressure. Non-condensable hydrocarbons may include hydrocarbons havingcarbon numbers less than 5.

As used herein, the term “heavy hydrocarbons” refers to hydrocarbonfluids that are highly viscous at ambient conditions (15° C. and 1 atmpressure). Heavy hydrocarbons may include highly viscous hydrocarbonfluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons mayinclude carbon and hydrogen, as well as smaller concentrations ofsulfur, oxygen, and nitrogen. Additional elements may also be present inheavy hydrocarbons in trace amounts. Heavy hydrocarbons may beclassified by API gravity. Heavy hydrocarbons generally have an APIgravity below about 20 degrees. Heavy oil, for example, generally has anAPI gravity of about 10 to 20 degrees, whereas tar generally has an APIgravity below about 10 degrees. The viscosity of heavy hydrocarbons isgenerally greater than about 100 centipoise at 15° C.

As used herein, the term “solid hydrocarbons” refers to any hydrocarbonmaterial that is found naturally in substantially solid form atformation conditions. Non-limiting examples include kerogen, coal,shungites, asphaltites, and natural mineral waxes.

As used herein, the term “formation hydrocarbons” refers to both heavyhydrocarbons and solid hydrocarbons that are contained in anorganic-rich rock formation. Formation hydrocarbons may be, but are notlimited to, kerogen, oil shale, coal, bitumen, tar, natural mineralwaxes, and asphaltites.

As used herein, the term “tar” refers to a viscous hydrocarbon thatgenerally has a viscosity greater than about 10,000 centipoise at 15° C.The specific gravity of tar generally is greater than 1.000. Tar mayhave an API gravity less than 10 degrees. “Tar sands” refers to aformation that has tar in it.

As used herein, the term “kerogen” refers to a solid, insolublehydrocarbon that principally contains carbon, hydrogen, nitrogen,oxygen, and sulfur. Oil shale contains kerogen.

As used herein, the term “bitumen” refers to a non-crystalline solid orviscous hydrocarbon material that is substantially soluble in carbondisulfide.

As used herein, the term “oil” refers to a hydrocarbon fluid containinga mixture of condensable hydrocarbons.

As used herein, the term “subsurface” refers to geologic strataoccurring below the earth's surface.

As used herein, the term “hydrocarbon-rich formation” refers to anyformation that contains more than trace amounts of hydrocarbons. Forexample, a hydrocarbon-rich formation may include portions that containhydrocarbons at a level of greater than 5 volume percent. Thehydrocarbons located in a hydrocarbon-rich formation may include, forexample, oil, natural gas, heavy hydrocarbons, and solid hydrocarbons.

As used herein, the term “organic-rich rock” refers to any rock matrixholding solid hydrocarbons and/or heavy hydrocarbons. Rock matrices mayinclude, but are not limited to, sedimentary rocks, shales, siltstones,sands, silicilytes, carbonates, and diatomites. Organic-rich rock maycontain kerogen.

As used herein, the term “formation” refers to any finite subsurfaceregion. The formation may contain one or more hydrocarbon-containinglayers, one or more non-hydrocarbon containing layers, an overburden,and/or an underburden of any subsurface geologic formation. An“overburden” is geological material above the formation of interest,while an “underburden” is geological material below the formation ofinterest. An overburden or underburden may include one or more differenttypes of substantially impermeable materials. For example, overburdenand/or underburden may include rock, shale, mudstone, or wet/tightcarbonate (i.e., an impermeable carbonate without hydrocarbons). Anoverburden and/or an underburden may include a hydrocarbon-containinglayer that is relatively impermeable. In some cases, the overburdenand/or underburden may be permeable.

As used herein, the term “organic-rich rock formation” refers to anyformation containing organic-rich rock. Organic-rich rock formationsinclude, for example, oil shale formations, coal formations, and tarsands formations.

As used herein, the term “pyrolysis” refers to the breaking of chemicalbonds through the application of heat. For example, pyrolysis mayinclude transforming a compound into one or more other substances byheat alone or by heat in combination with an oxidant. Pyrolysis mayinclude modifying the nature of the compound by addition of hydrogenatoms which may be obtained from molecular hydrogen, water, carbondioxide, or carbon monoxide. Heat may be transferred to a section of theformation to cause pyrolysis.

As used herein, the term “water-soluble minerals” refers to mineralsthat are soluble in water. Water-soluble minerals include, for example,nahcolite (sodium bicarbonate), soda ash (sodium carbonate), dawsonite(NaAl(CO₃)(OH)₂), or combinations thereof. Substantial solubility mayrequire heated water and/or a non-neutral pH solution.

As used herein, the term “formation water-soluble minerals” refers towater-soluble minerals that are found naturally in a formation.

As used herein, the term “subsidence” refers to a downward movement of asurface relative to an initial elevation of the surface.

As used herein, the term “thickness” of a layer refers to the distancebetween the upper and lower boundaries of a cross section of a layer,wherein the distance is measured normal to the average tilt of the crosssection.

As used herein, the term “thermal fracture” refers to fractures createdin a formation caused directly or indirectly by expansion or contractionof a portion of the formation and/or fluids within the formation, whichin turn is caused by increasing/decreasing the temperature of theformation and/or fluids within the formation, and/or byincreasing/decreasing a pressure of fluids within the formation due toheating. Thermal fractures may propagate into or form in neighboringregions significantly cooler than the heated zone.

As used herein, the term “hydraulic fracture” refers to a fracture atleast partially propagated into a formation, wherein the fracture iscreated through injection of pressurized fluids into the formation.While the term “hydraulic fracture” is used, the inventions herein arenot limited to use in hydraulic fractures. The invention is suitable foruse in any fracture created in any manner considered to be suitable byone skilled in the art. The fracture may be artificially held open byinjection of a proppant material. Hydraulic fractures may besubstantially horizontal in orientation, substantially vertical inorientation, or oriented along any other plane.

As used herein, the term “wellbore” refers to a hole in the subsurfacemade by drilling or insertion of a conduit into the subsurface. Awellbore may have a substantially circular cross section, or othercross-sectional shapes (e.g., circles, ovals, squares, rectangles,triangles, slits, or other regular or irregular shapes). As used herein,the term “well”, when referring to an opening in the formation, may beused interchangeably with the term “wellbore.”

The inventions are described herein in connection with certain specificembodiments. However, to the extent that the following detaileddescription is specific to a particular embodiment or a particular use,such is intended to be illustrative only and is not to be construed aslimiting the scope of the invention.

As discussed herein, some embodiments of the invention include or haveapplication related to an in situ method of recovering naturalresources. The natural resources may be recovered from an organic-richrock formation including, for example, an oil shale formation. Theorganic-rich rock formation may include formation hydrocarbonsincluding, for example, kerogen, coal, and heavy hydrocarbons. In someembodiments of the invention the natural resources may includehydrocarbon fluids including, for example, products of the pyrolysis offormation hydrocarbons such as shale oil. In some embodiments of theinvention the natural resources may also include water-soluble mineralsincluding, for example, nahcolite (sodium bicarbonate, or 2NaHCO₃), sodaash (sodium carbonate, or Na₂CO₃) and dawsonite (NaAl(CO₃)(OH)₂).

FIG. 1 presents a perspective view of an illustrative oil shaledevelopment area 10. A surface 12 of the development area 10 isindicated. Below the surface is an organic-rich rock formation 16. Theillustrative subsurface formation 16 contains formation hydrocarbons(such as, for example, kerogen) and possibly valuable water-solubleminerals (such as, for example, nahcolite). It is understood that therepresentative formation 16 may be any organic-rich rock formation,including a rock matrix containing coal or tar sands, for example. Inaddition, the rock matrix making up the formation 16 may be permeable,semi-permeable or essentially non-permeable. The present inventions areparticularly advantageous in oil shale development areas initiallyhaving very limited or effectively no fluid permeability.

In order to access formation 16 and recover natural resources therefrom,a plurality of wellbores is formed. Wellbores are shown at 14 in FIG. 1.The representative wellbores 14 are essentially vertical in orientationrelative to the surface 12. However, it is understood that some or allof the wellbores 14 could deviate into an obtuse or even horizontalorientation. In the arrangement of FIG. 1, each of the wellbores 14 iscompleted in the oil shale formation 16. The completions may be eitheropen or cased hole. The well completions may also include propped orunpropped hydraulic fractures emanating therefrom.

In the view of FIG. 1, only seven wellbores 14 are shown. However, it isunderstood that in an oil shale development project, numerous additionalwellbores 14 will most likely be drilled. The wellbores 14 may belocated in relatively close proximity, being from 10 feet to up to 300feet in separation. In some embodiments, a well spacing of 15 to 25 feetis provided. Typically, the wellbores 14 are also completed at shallowdepths, being from 200 to 5,000 feet at total depth. In some embodimentsthe oil shale formation targeted for in situ retorting is at a depthgreater than 200 feet below the surface or alternatively 400 feet belowthe surface. Alternatively, conversion and production occur at depthsbetween 500 and 2,500 feet.

The wellbores 14 will be selected for certain functions and may bedesignated as heat injection wells, water injection wells, oilproduction wells and/or water-soluble mineral solution production wells.In one aspect, the wellbores 14 are dimensioned to serve two, three, orall four of these purposes in designated sequences. Suitable tools andequipment may be sequentially run into and removed from the wellbores 14to serve the various purposes.

A fluid processing facility 17 is also shown schematically. The fluidprocessing facility 17 is equipped to receive fluids produced from theorganic-rich rock formation 16 through one or more pipelines or flowlines 18. The fluid processing facility 17 may include equipmentsuitable for receiving and separating oil, gas, and water produced fromthe heated formation. The fluid processing facility 17 may furtherinclude equipment for separating out dissolved water-soluble mineralsand/or migratory contaminant species, including, for example, dissolvedorganic contaminants, metal contaminants, or ionic contaminants in theproduced water recovered from the organic-rich rock formation 16. Thecontaminants may include, for example, aromatic hydrocarbons such asbenzene, toluene, xylene, and tri-methylbenzene. The contaminants mayalso include polyaromatic hydrocarbons such as anthracene, naphthalene,chrysene and pyrene. Metal contaminants may include species containingarsenic, boron, chromium, mercury, selenium, lead, vanadium, nickel,cobalt, molybdenum, or zinc. Ionic contaminant species may include, forexample, sulfates, chlorides, fluorides, lithium, potassium, aluminum,ammonia, and nitrates.

In order to recover oil, gas, and sodium (or other) water-solubleminerals, a series of steps may be undertaken. FIG. 2 presents a flowchart demonstrating a method of in situ thermal recovery of oil and gasfrom an organic-rich rock formation 100, in one embodiment. It isunderstood that the order of some of the steps from FIG. 2 may bechanged, and that the sequence of steps is merely for illustration.

First, the oil shale (or other organic-rich rock) formation 16 isidentified within the development area 10. This step is shown in box110. Optionally, the oil shale formation may contain nahcolite or othersodium minerals. The targeted development area within the oil shaleformation may be identified by measuring or modeling the depth,thickness and organic richness of the oil shale as well as evaluatingthe position of the organic-rich rock formation relative to other rocktypes, structural features (e.g. faults, anticlines or synclines), orhydrogeological units (i.e. aquifers). This is accomplished by creatingand interpreting maps and/or models of depth, thickness, organicrichness and other data from available tests and sources. This mayinvolve performing geological surface surveys, studying outcrops,performing seismic surveys, and/or drilling boreholes to obtain coresamples from subsurface rock. Rock samples may be analyzed to assesskerogen content and hydrocarbon fluid generating capability.

The kerogen content of the organic-rich rock formation may beascertained from outcrop or core samples using a variety of data. Suchdata may include organic carbon content, hydrogen index, and modifiedFischer assay analyses. Subsurface permeability may also be assessed viarock samples, outcrops, or studies of ground water flow. Furthermore theconnectivity of the development area to ground water sources may beassessed.

Next, a plurality of wellbores 14 is formed across the targeteddevelopment area 10. This step is shown schematically in box 115. Thepurposes of the wellbores 14 are set forth above and need not berepeated. However, it is noted that for purposes of the wellboreformation step of box 115, only a portion of the wells need be completedinitially. For instance, at the beginning of the project heat injectionwells are needed, while a majority of the hydrocarbon production wellsare not yet needed. Production wells may be brought in once conversionbegins, such as after 4 to 12 months of heating.

It is understood that petroleum engineers will develop a strategy forthe best depth and arrangement for the wellbores 14, depending uponanticipated reservoir characteristics, economic constraints, and workscheduling constraints. In addition, engineering staff will determinewhat wellbores 14 shall be used for initial formation 16 heating. Thisselection step is represented by box 120.

Concerning heat injection wells, there are various methods for applyingheat to the organic-rich rock formation 16. The present methods are notlimited to the heating technique employed unless specifically so statedin the claims. The heating step is represented generally by box 130.Preferably, for in situ processes the heating of a production zone takesplace over a period of months, or even four or more years.

The formation 16 is heated to a temperature sufficient to pyrolyze atleast a portion of the oil shale in order to convert the kerogen tohydrocarbon fluids. The bulk of the target zone of the formation may beheated to between 270° C. to 800° C. Alternatively, the targeted volumeof the organic-rich formation is heated to at least 350° C. to createproduction fluids. The conversion step is represented in FIG. 2 by box135. The resulting liquids and hydrocarbon gases may be refined intoproducts which resemble common commercial petroleum products. Suchliquid products include transportation fuels such as diesel, jet fueland naphtha. Generated gases include light alkanes, light alkenes, H₂,CO₂, CO, and NH₃.

Conversion of the oil shale will create permeability in the oil shalesection in rocks that were originally impermeable. Preferably, theheating and conversion processes of boxes 130 and 135, occur over alengthy period of time. In one aspect, the heating period is from threemonths to four or more years. Also as an optional part of box 135, theformation 16 may be heated to a temperature sufficient to convert atleast a portion of nahcolite, if present, to soda ash. Heat applied tomature the oil shale and recover oil and gas will also convert nahcoliteto sodium carbonate (soda ash), a related sodium mineral. The process ofconverting nahcolite (sodium bicarbonate) to soda ash (sodium carbonate)is described herein.

In connection with the heating step 130, the rock formation 16 mayoptionally be fractured to aid heat transfer or later hydrocarbon fluidproduction. The optional fracturing step is shown in box 125. Fracturingmay be accomplished by creating thermal fractures within the formationthrough application of heat. By heating the organic-rich rock andtransforming the kerogen to oil and gas, the permeability of portions ofthe formation are increased via thermal fracture formation andsubsequent production of a portion of the hydrocarbon fluids generatedfrom the kerogen. Alternatively, a process known as hydraulic fracturingmay be used. Hydraulic fracturing is a process known in the art of oiland gas recovery where a fracture fluid is pressurized within thewellbore above the fracture pressure of the formation, thus developingfracture planes within the formation to relieve the pressure generatedwithin the wellbore. Hydraulic fractures may be used to createadditional permeability in portions of the formation and/or be used toprovide a planar source for heating.

International patent publication WO 2005/010320 entitled “Methods ofTreating a Subterranean Formation to Convert Organic Matter intoProducible Hydrocarbons” describes one use of hydraulic fracturing, andis incorporated herein by reference in its entirety. This internationalpatent publication teaches the use of electrically conductive fracturesto heat oil shale. A heating element is constructed by forming wellboresand then hydraulically fracturing the oil shale formation around thewellbores. The fractures are filled with an electrically conductivematerial which forms the heating element. Calcined petroleum coke is anexemplary suitable conductant material. Preferably, the fractures arecreated in a vertical orientation extending from horizontal wellbores.Electricity may be conducted through the conductive fractures from theheel to the toe of each well. The electrical circuit may be completed byan additional horizontal well that intersects one or more of thevertical fractures near the toe to supply the opposite electricalpolarity. The WO 2005/010320 process creates an “in situ toaster” thatartificially matures oil shale through the application of electric heat.Thermal conduction heats the oil shale to conversion temperatures inexcess of 300° C., causing artificial maturation.

It is noted that U.S. Pat. No. 3,137,347 also describes the use ofgranular conductive materials to connect subsurface electrodes for thein situ heating of oil shale. The '347 patent envisions the granularmaterial being a primary source of heat until the oil shale undergoespyrolysis. At that point, the oil shale itself is said to becomeelectrically conductive. Heat generated within the formation and heatconducted into the surrounding formation due to the passing of currentthrough the shale oil material itself is claimed to generate hydrocarbonfluids for production.

As part of the hydrocarbon fluid production process 100, certain wells14 may be designated as oil and gas production wells. This step isdepicted by box 140. Oil and gas production might not be initiated untilit is determined that the kerogen has been sufficiently retorted toallow maximum recovery of oil and gas from the formation 16. In someinstances, dedicated production wells are not drilled until after heatinjection wells (box 130) have been in operation for a period of severalweeks or months. Thus, box 140 may include the formation of additionalwellbores 14. In other instances, selected heater wells are converted toproduction wells.

After certain wellbores 14 have been designated as oil and gasproduction wells, oil and/or gas is produced from the wellbores 14. Theoil and/or gas production process is shown at box 145. At this stage(box 145), any water-soluble minerals, such as nahcolite and convertedsoda ash may remain substantially trapped in the rock formation 16 asfinely disseminated crystals or nodules within the oil shale beds, andare not produced. However, some nahcolite and/or soda ash may bedissolved in the water created during heat conversion (box 135) withinthe formation. Thus, production fluids may contain not only hydrocarbonfluids, but also aqueous fluid containing water-soluble minerals. Insuch case, the production fluids may be separated into a hydrocarbonstream and an aqueous stream at a surface facility. Thereafter thewater-soluble minerals and any migratory contaminant species may berecovered from the aqueous stream.

Box 150 presents an optional next step in the oil and gas recoverymethod 100. Here, certain wellbores 14 are designated as water oraqueous fluid injection wells. Aqueous fluids are solutions of waterwith other species. The water may constitute “brine,” and may includedissolved inorganic salts of chloride, sulfates and carbonates of GroupI and II elements of The Periodic Table of Elements. Organic salts canalso be present in the aqueous fluid. The water may alternatively befresh water containing other species. The other species may be presentto alter the pH. Alternatively, the other species may reflect theavailability of brackish water not saturated in the species wished to beleached from the subsurface. Preferably, the water injection wells areselected from some or all of the wellbores used for heat injection orfor oil and/or gas production. However, the scope of the step of box 150may include the drilling of yet additional wellbores 14 for use asdedicated water injection wells. In this respect, it may be desirable tocomplete water injection wells along a periphery of the development area10 in order to create a boundary of high pressure.

Next, optionally water or an aqueous fluid is injected through the waterinjection wells and into the oil shale formation 16. This step is shownat box 155. The water may be in the form of steam or pressurized hotwater. Alternatively the injected water may be cool and becomes heatedas it contacts the previously heated formation. The injection processmay further induce fracturing. This process may create fingered cavernsand brecciated zones in the nahcolite-bearing intervals some distance,for example up to 200 feet out, from the water injection wellbores. Inone aspect, a gas cap, such as nitrogen, may be maintained at the top ofeach “cavern” to prevent vertical growth.

Along with the designation of certain wellbores 14 as water injectionwells, the design engineers may also designate certain wellbores 14 aswater or water-soluble mineral solution production wells. This step isshown in box 160. These wells may be the same as wells used topreviously produce hydrocarbons or inject heat. These recovery wells maybe used to produce an aqueous solution of dissolved water-solubleminerals and other species, including, for example, migratorycontaminant species. For example, the solution may be one primarily ofdissolved soda ash. This step is shown in box 165. Alternatively, singlewellbores may be used to both inject water and then to recover a sodiummineral solution. Thus, box 165 includes the option of using the samewellbores 14 for both water injection and solution production (Box 165).

Temporary control of the migration of the migratory contaminant species,especially during the pyrolysis process, can be obtained via placementof the injection and production wells 14 such that fluid flow out of theheated zone is minimized. Typically, this involves placing injectionwells at the periphery of the heated zone so as to cause pressuregradients which prevent flow inside the heated zone from leaving thezone.

FIG. 3 is a cross-sectional view of an illustrative oil shale formationthat is within or connected to ground water aquifers and a formationleaching operation. Four separate oil shale formation zones are depicted(23, 24, 25 and 26) within the oil shale formation. The water aquifersare below the ground surface 27, and are categorized as an upper aquifer20 and a lower aquifer 22. Intermediate the upper and lower aquifers isan aquitard 21. It can be seen that certain zones of the formation areboth aquifers or aquitards and oil shale zones. A plurality of wells(28, 29, 30 and 31) is shown traversing vertically downward through theaquifers. One of the wells is serving as a water injection well 31,while another is serving as a water production well 30. In this way,water is circulated 32 through at least the lower aquifer 22.

FIG. 3 shows diagrammatically water circulating 32 through an oil shalevolume 33 that was heated, that resides within or is connected to anaquifer 22, and from which hydrocarbon fluids were previously recovered.Introduction of water via the water injection well 31 forces water intothe previously heated oil shale 33 and water-soluble minerals andmigratory contaminants species are swept to the water production well30. The water may then be processed in a facility 34 wherein thewater-soluble minerals (e.g. nahcolite or soda ash) and the migratorycontaminants may be substantially removed from the water stream. Wateris then reinjected into the oil shale volume 33 and the formationleaching is repeated. This leaching with water is intended to continueuntil levels of migratory contaminant species are at environmentallyacceptable levels within the previously heated oil shale zone 33. Thismay require 1 cycle, 2 cycles, 5 cycles or more cycles of formationleaching, where a single cycle indicates injection and production ofapproximately one pore volume of water. It is understood that there maybe numerous water injection and water production wells in an actual oilshale development. Moreover, the system may include monitoring wells (28and 29) which can be utilized during the oil shale heating phase, theshale oil production phase, the leaching phase, or during anycombination of these phases to monitor for migratory contaminant speciesand/or water-soluble minerals.

In some fields, formation hydrocarbons, such as oil shale, may exist inmore than one subsurface formation. In some instances, the organic-richrock formations may be separated by rock layers that arehydrocarbon-free or that otherwise have little or no commercial value.Therefore, it may be desirable for the operator of a field underhydrocarbon development to undertake an analysis as to which of thesubsurface, organic-rich rock formations to target or in which orderthey should be developed.

The organic-rich rock formation may be selected for development based onvarious factors. One such factor is the thickness of the hydrocarboncontaining layer within the formation. Greater pay zone thickness mayindicate a greater potential volumetric production of hydrocarbonfluids. Each of the hydrocarbon containing layers may have a thicknessthat varies depending on, for example, conditions under which theformation hydrocarbon containing layer was formed. Therefore, anorganic-rich rock formation will typically be selected for treatment ifthat formation includes at least one formation hydrocarbon-containinglayer having a thickness sufficient for economical production ofproduced fluids.

An organic-rich rock formation may also be chosen if the thickness ofseveral layers that are closely spaced together is sufficient foreconomical production of produced fluids. For example, an in situconversion process for formation hydrocarbons may include selecting andtreating a layer within an organic-rich rock formation having athickness of greater than about 5 meters, 10 meters, 50 meters, or even100 meters. In this manner, heat losses (as a fraction of total injectedheat) to layers formed above and below an organic-rich rock formationmay be less than such heat losses from a thin layer of formationhydrocarbons. A process as described herein, however, may also includeselecting and treating layers that may include layers substantially freeof formation hydrocarbons or thin layers of formation hydrocarbons.

The richness of one or more organic-rich rock formations may also beconsidered. Richness may depend on many factors including the conditionsunder which the formation hydrocarbon containing layer was formed, anamount of formation hydrocarbons in the layer, and/or a composition offormation hydrocarbons in the layer. A thin and rich formationhydrocarbon layer may be able to produce significantly more valuablehydrocarbons than a much thicker, less rich formation hydrocarbon layer.Of course, producing hydrocarbons from a formation that is both thickand rich is desirable.

The kerogen content of an organic-rich rock formation may be ascertainedfrom outcrop or core samples using a variety of data. Such data mayinclude organic carbon content, hydrogen index, and modified Fischerassay analyses. The Fischer Assay is a standard method which involvesheating a sample of a formation hydrocarbon containing layer toapproximately 500° C. in one hour, collecting fluids produced from theheated sample, and quantifying the amount of fluids produced.

Subsurface formation permeability may also be assessed via rock samples,outcrops, or studies of ground water flow. Furthermore the connectivityof the development area to ground water sources may be assessed. Thus,an organic-rich rock formation may be chosen for development based onthe permeability or porosity of the formation matrix even if thethickness of the formation is relatively thin.

Other factors known to petroleum engineers may be taken intoconsideration when selecting a formation for development. Such factorsinclude depth of the perceived pay zone, stratigraphic proximity offresh ground water to kerogen-containing zones, continuity of thickness,and other factors. For instance, the assessed fluid production contentwithin a formation will also effect eventual volumetric production.

In producing hydrocarbon fluids from an oil shale field, it may bedesirable to control the migration of pyrolyzed fluids. In someinstances, this includes the use of injection wells such as well 31,particularly around the periphery of the field. Such wells may injectwater, steam, CO₂, heated methane, or other fluids to drive crackedkerogen fluids inwardly towards production wells. In some embodiments,physical barriers may be placed around the area of the organic-rich rockformation under development. One example of a physical barrier involvesthe creation of freeze walls. Freeze walls are formed by circulatingrefrigerant through peripheral wells to substantially reduce thetemperature of the rock formation. This, in turn, prevents thepyrolyzation of kerogen present at the periphery of the field and theoutward migration of oil and gas. Freeze walls will also cause nativewater in the formation along the periphery to freeze.

The use of subsurface freezing to stabilize poorly consolidated soils orto provide a barrier to fluid flow is known in the art. ShellExploration and Production Company has discussed the use of freeze wallsfor oil shale production in several patents, including U.S. Pat. No.6,880,633 and U.S. Pat. No. 7,032,660. Shell's '660 patent usessubsurface freezing to protect against groundwater flow and groundwatercontamination during in situ shale oil production. Additional patentsthat disclose the use of so-called freeze walls are U.S. Pat. No.3,528,252, U.S. Pat. No. 3,943,722, U.S. Pat. No. 3,729,965, U.S. Pat.No. 4,358,222, U.S. Pat. No. 4,607,488, and WO Pat. No. 98996480.

As noted above, several different types of wells may be used in thedevelopment of an organic-rich rock formation, including, for example,an oil shale field. For example, the heating of the organic-rich rockformation may be accomplished through the use of heater wells. Theheater wells may include, for example, electrical resistance heatingelements. The production of hydrocarbon fluids from the formation may beaccomplished through the use of wells completed for the production offluids. The injection of an aqueous fluid may be accomplished throughthe use of injection wells. Finally, the production of an aqueoussolution may be accomplished through use of solution production wells.

The different wells listed above may be used for more than one purpose.Stated another way, wells initially completed for one purpose may laterbe used for another purpose, thereby lowering project costs and/ordecreasing the time required to perform certain tasks. For example, oneor more of the production wells may also be used as injection wells forlater injecting water into the organic-rich rock formation.Alternatively, one or more of the production wells may also be used assolution production wells for later producing an aqueous solution fromthe organic-rich rock formation.

In other aspects, production wells (and in some circumstances heaterwells) may initially be used as dewatering wells (e.g., before heatingis begun and/or when heating is initially started). In addition, in somecircumstances dewatering wells can later be used as production wells(and in some circumstances heater wells). As such, the dewatering wellsmay be placed and/or designed so that such wells can be later used asproduction wells and/or heater wells. The heater wells may be placedand/or designed so that such wells can be later used as production wellsand/or dewatering wells. The production wells may be placed and/ordesigned so that such wells can be later used as dewatering wells and/orheater wells. Similarly, injection wells may be wells that initiallywere used for other purposes (e.g., heating, production, dewatering,monitoring, etc.), and injection wells may later be used for otherpurposes. Similarly, monitoring wells may be wells that initially wereused for other purposes (e.g., heating, production, dewatering,injection, etc.). Finally, monitoring wells may later be used for otherpurposes such as water production.

It is desirable to arrange the various wells for an oil shale field in apre-planned pattern. For instance, heater wells may be arranged in avariety of patterns including, but not limited to triangles, squares,hexagons, and other polygons. The pattern may include a regular polygonto promote uniform heating through at least the portion of the formationin which the heater wells are placed. The pattern may also be a linedrive pattern. A line drive pattern generally includes a first lineararray of heater wells, a second linear array of heater wells, and aproduction well or a linear array of production wells between the firstand second linear array of heater wells. Interspersed among the heaterwells are typically one or more production wells. The injection wellsmay likewise be disposed within a repetitive pattern of units, which maybe similar to or different from that used for the heater wells.

One method to reduce the number of wells is to use a single well as botha heater well and a production well. Reduction of the number of wells byusing single wells for sequential purposes can reduce project costs. Oneor more monitoring wells may be disposed at selected points in thefield. The monitoring wells may be configured with one or more devicesthat measure a temperature, a pressure, and/or a property of a fluid inthe wellbore. In some instances, a heater well may also serve as amonitoring well, or otherwise be instrumented.

Another method for reducing the number of heater wells is to use wellpatterns. Regular patterns of heater wells equidistantly spaced from aproduction well may be used. The patterns may form equilateraltriangular arrays, hexagonal arrays, or other array patterns. The arraysof heater wells may be disposed such that a distance between each heaterwell is less than about 70 feet (21 meters). A portion of the formationmay be heated with heater wells disposed substantially parallel to aboundary of the hydrocarbon formation.

In alternative embodiments, the array of heater wells may be disposedsuch that a distance between each heater well may be less than about 100feet, or 50 feet, or 30 feet. Regardless of the arrangement of ordistance between the heater wells, in certain embodiments, a ratio ofheater wells to production wells disposed within a organic-rich rockformation may be greater than about 5, 8, 10, 20, or more.

In one embodiment, individual production wells are surrounded by at mostone layer of heater wells. This may include arrangements such as 5-spot,7-spot, or 9-spot arrays, with alternating rows of production and heaterwells. In another embodiment, two layers of heater wells may surround aproduction well, but with the heater wells staggered so that a clearpathway exists for the majority of flow away from the further heaterwells. Flow and reservoir simulations may be employed to assess thepathways and temperature history of hydrocarbon fluids generated in situas they migrate from their points of origin to production wells.

FIG. 4 provides a plan view of an illustrative heater well arrangementusing more than one layer of heater wells. The heater well arrangementis used in connection with the production of hydrocarbons from a shaleoil development area 400. In FIG. 4, the heater well arrangement employsa first layer of heater wells 410, surrounded by a second layer ofheater wells 420. The heater wells in the first layer 410 are referencedat 431, while the heater wells in the second layer 420 are referenced at432.

A production well 440 is shown central to the well layers 410 and 420.It is noted that the heater wells 432 in the second layer 420 of wellsare offset from the heater wells 431 in the first layer 410 of wells,relative to the production well 440. The purpose is to provide aflowpath for converted hydrocarbons that minimizes travel near a heaterwell in the first layer 410 of heater wells. This, in turn, minimizessecondary cracking of hydrocarbons converted from kerogen ashydrocarbons flow from the second layer of wells 420 to the productionwells 440.

In the illustrative arrangement of FIG. 4, the first layer 410 and thesecond layer 420 each defines a 5-spot pattern. However, it isunderstood that other patterns may be employed, such as 3-spot or 6-spotpatterns. In any instance, a plurality of heater wells 431 comprising afirst layer of heater wells 410 is placed around a production well 440,with a second plurality of heater wells 432 comprising a second layer ofheater wells 420 placed around the first layer 410.

The heater wells in the two layers also may be arranged such that themajority of hydrocarbons generated by heat from each heater well 432 inthe second layer 420 are able to migrate to a production well 440without passing substantially near a heater well 431 in the first layer410. The heater wells 431, 432 in the two layers 410, 420 further may bearranged such that the majority of hydrocarbons generated by heat fromeach heater well 432 in the second layer 420 are able to migrate to theproduction well 440 without passing through a zone of substantiallyincreasing formation temperature.

Another method for reducing the number of heater wells is to use wellpatterns that are elongated in a particular direction, particularly in adirection determined to provide the most efficient thermal conductivity.Heat convection may be affected by various factors such as beddingplanes and stresses within the formation. For instance, heat convectionmay be more efficient in the direction perpendicular to the leasthorizontal principal stress on the formation. In some instances, heatconvection may be more efficient in the direction parallel to the leasthorizontal principal stress. Elongation may be practiced in, forexample, line drive patterns or spot patterns.

In connection with the development of a shale oil field, it may bedesirable that the progression of heat through the subsurface inaccordance with steps 130 and 135 be uniform. However, for variousreasons the heating and maturation of formation hydrocarbons in asubsurface formation may not proceed uniformly despite a regulararrangement of heater and production wells. Heterogeneities in the oilshale properties and formation structure may cause certain local areasto be more or less efficient in terms of pyrolysis. Moreover, formationfracturing which occurs due to the heating and maturation of the oilshale can lead to an uneven distribution of preferred pathways and,thus, increase flow to certain production wells and reduce flow toothers. Uneven fluid maturation may be an undesirable condition sincecertain subsurface regions may receive more heat energy than necessarywhere other regions receive less than desired. This, in turn, leads tothe uneven flow and recovery of production fluids. Produced oil quality,overall production rate, and/or ultimate recoveries may be reduced.

To detect uneven flow conditions, production and heater wells may beinstrumented with sensors. Sensors may include equipment to measuretemperature, pressure, flow rates, and/or compositional information.Data from these sensors can be processed via simple rules or input todetailed simulations to reach decisions on how to adjust heater andproduction wells to improve subsurface performance. Production wellperformance may be adjusted by controlling backpressure or throttling onthe well. Heater well performance may also be adjusted by controllingenergy input. Sensor readings may also sometimes imply mechanicalproblems with a well or downhole equipment which requires repair,replacement, or abandonment.

In one embodiment, flow rate, compositional, temperature and/or pressuredata are utilized from two or more wells as inputs to a computeralgorithm to control heating rate and/or production rates. Unmeasuredconditions at or in the neighborhood of the well are then estimated andused to control the well. For example, in situ fracturing behavior andkerogen maturation are estimated based on thermal, flow, andcompositional data from a set of wells. In another example, wellintegrity is evaluated based on pressure data, well temperature data,and estimated in situ stresses. In a related embodiment the number ofsensors is reduced by equipping only a subset of the wells withinstruments, and using the results to interpolate, calculate, orestimate conditions at uninstrumented wells. Certain wells may have onlya limited set of sensors (e.g., wellhead temperature and pressure only)where others have a much larger set of sensors (e.g., wellheadtemperature and pressure, bottomhole temperature and pressure,production composition, flow rate, electrical signature, casing strain,etc.).

As noted above, there are various methods for applying heat to anorganic-rich rock formation. For example, one method may includeelectrical resistance heaters disposed in a wellbore or outside of awellbore. One such method involves the use of electrical resistiveheating elements in a cased or uncased wellbore. Electrical resistanceheating involves directly passing electricity through a conductivematerial such that resistive losses cause it to heat the conductivematerial. Other heating methods include the use of downhole combustors,in situ combustion, radio-frequency (RF) electrical energy, or microwaveenergy. Still others include injecting a hot fluid into the oil shaleformation to directly heat it. The hot fluid may or may not becirculated.

One method for formation heating involves the use of electricalresistors in which an electrical current is passed through a resistivematerial which dissipates the electrical energy as heat. This method isdistinguished from dielectric heating in which a high-frequencyoscillating electric current induces electrical currents in nearbymaterials and causes them to heat. The electric heater may include aninsulated conductor, an elongated member disposed in the opening, and/ora conductor disposed in a conduit. An early patent disclosing the use ofelectrical resistance heaters to produce oil shale in situ is U.S. Pat.No. 1,666,488. The '488 patent issued to Crawshaw in 1928. Since 1928,various designs for downhole electrical heaters have been proposed.Illustrative designs are presented in U.S. Pat. No. 1,701,884, U.S. Pat.No. 3,376,403, U.S. Pat. No. 4,626,665, U.S. Pat. No. 4,704,514, andU.S. Pat. No. 6,023,554).

A review of application of electrical heating methods for heavy oilreservoirs is given by R. Sierra and S. M. Farouq Ali, “PromisingProgress in Field Application of Reservoir Electrical Heating Methods”,Society of Petroleum Engineers Paper 69709, 2001. The entire disclosureof this reference is hereby incorporated by reference.

Certain previous designs for in situ electrical resistance heatersutilized solid, continuous heating elements (e.g., metal wires orstrips). However, such elements may lack the necessary robustness forlong-term, high temperature applications such as oil shale maturation.As the formation heats and the oil shale matures, significant expansionof the rock occurs. This leads to high stresses on wells intersectingthe formation. These stresses can lead to bending and stretching of thewellbore pipe and internal components. Cementing (e.g., U.S. Pat. No.4,886,118) or packing (e.g., U.S. Pat. No. 2,732,195) a heating elementin place may provide some protection against stresses, but some stressesmay still be transmitted to the heating element.

Although the above processes are applied in these examples to generatehydrocarbons from oil shale, the idea may also be applicable to heavyoil reservoirs, tar sands, or gas hydrates. In these instances, theelectrical heat supplied would serve to reduce hydrocarbon viscosity orto melt hydrates. U.S. Pat. No. 6,148,911 discusses the use of anelectrically conductive proppant to release gas from a hydrateformation. It is also known to apply a voltage across a formation usingbrine as the electrical conductor and heating element. However, it isbelieved that the use of formation brine as a heating element isinadequate for shale conversion as it is limited to temperatures belowthe in situ boiling point of water. Thus, the circuit fails when thewater vaporizes.

The purpose for heating the organic-rich rock formation is to pyrolyzeat least a portion of the solid formation hydrocarbons to createhydrocarbon fluids. The solid formation hydrocarbons may be pyrolyzed insitu by raising the organic-rich rock formation, (or zones within theformation), to a pyrolyzation temperature. In certain embodiments, thetemperature of the formation may be slowly raised through the pyrolysistemperature range. For example, an in situ conversion process mayinclude heating at least a portion of the organic-rich rock formation toraise the average temperature of the zone above about 270° C. at a rateless than a selected amount (e.g., about 10° C., 5° C.; 3° C., 1° C.,0.5° C., or 0.1° C.) per day. In a further embodiment, the portion maybe heated such that an average temperature of the selected zone may beless than about 375° C. or, in some embodiments, less than about 400° C.The formation may be heated such that a temperature within the formationreaches (at least) an initial pyrolyzation temperature, that is, atemperature at the lower end of the temperature range where pyrolyzationbegins to occur.

The pyrolysis temperature range may vary depending on the types offormation hydrocarbons within the formation, the heating methodology,and the distribution of heating sources. For example, a pyrolysistemperature range may include temperatures between about 270° C. andabout 900° C. Alternatively, the bulk of the target zone of theformation may be heated to between 300° to 600° C. In an alternativeembodiment, a pyrolysis temperature range may include temperaturesbetween about 270° C. to about 500° C.

Preferably, for in situ processes the heating of a production zone takesplace over a period of months, or even four or more years.Alternatively, the formation may be heated for one to fifteen years,alternatively, 3 to 10 years, 1.5 to 7 years, or 2 to 5 years. The bulkof the target zone of the formation may be heated to between 270° to800° C. Preferably, the bulk of the target zone of the formation isheated to between 300° to 600° C. Alternatively, the bulk of the targetzone is ultimately heated to a temperature below 400° C. (752° F.).

In the production of oil and gas resources, it may be desirable to usethe produced hydrocarbons as a source of power for ongoing operations.This may be applied to the development of oil and gas resources from oilshale. In this respect, when electrically resistive heaters are used inconnection with in situ shale oil recovery, large amounts of power arerequired.

Electrical power may be obtained from turbines that turn generators. Itmay be economically advantageous to power the gas turbines by utilizingproduced gas from the field. However, such produced gas must becarefully controlled so not to damage the turbine, cause the turbine tomisfire, or generate excessive pollutants (e.g., NO_(x)).

One source of problems for gas turbines is the presence of contaminantswithin the fuel. Contaminants include solids, water, heavy componentspresent as liquids, and hydrogen sulfide. Additionally, the combustionbehavior of the fuel is important. Combustion parameters to considerinclude heating value, specific gravity, adiabatic flame temperature,flammability limits, autoignition temperature, autoignition delay time,and flame velocity. Wobbe Index (WI) is often used as a key measure offuel quality. WI is equal to the ratio of the lower heating value to thesquare root of the gas specific gravity. Control of the fuel's WobbeIndex to a target value and range of, for example, 10% or 20% can allowsimplified turbine design and increased optimization of performance.

Fuel quality control may be useful for shale oil developments where theproduced gas composition may change over the life of the field and wherethe gas typically has significant amounts of CO₂, CO, and H₂ in additionto light hydrocarbons. Commercial scale oil shale retorting is expectedto produce a gas composition that changes with time.

Inert gases in the turbine fuel can increase power generation byincreasing mass flow while maintaining a flame temperature in adesirable range. Moreover inert gases can lower flame temperature andthus reduce NO_(x) pollutant generation. Gas generated from oil shalematuration may have significant CO₂ content. Therefore, in certainembodiments of the production processes, the CO₂ content of the fuel gasis adjusted via separation or addition in the surface facilities tooptimize turbine performance.

Achieving a certain hydrogen content for low-BTU fuels may also bedesirable to achieve appropriate burn properties. In certain embodimentsof the processes herein, the H₂ content of the fuel gas is adjusted viaseparation or addition in the surface facilities to optimize turbineperformance. Adjustment of H₂ content in non-shale oil surfacefacilities utilizing low BTU fuels has been discussed in the patentliterature (e.g., U.S. Pat. No. 6,684,644 and U.S. Pat. No. 6,858,049,the entire disclosures of which are hereby incorporated by reference).

As noted, the process of heating formation hydrocarbons within anorganic-rich rock formation, for example, by pyrolysis, may generatefluids. The heat-generated fluids may include water which is vaporizedwithin the formation. In addition, the action of heating kerogenproduces pyrolysis fluids which tend to expand upon heating. Theproduced pyrolysis fluids may include not only water, but also, forexample, hydrocarbons, oxides of carbon, ammonia, molecular nitrogen,and molecular hydrogen. Therefore, as temperatures within a heatedportion of the formation increase, a pressure within the heated portionmay also increase as a result of increased fluid generation, molecularexpansion, and vaporization of water. Thus, some corollary existsbetween subsurface pressure in an oil shale formation and the fluidpressure generated during pyrolysis. This, in turn, indicates thatformation pressure may be monitored to detect the progress of a kerogenconversion process.

The pressure within a heated portion of an organic-rich rock formationdepends on other reservoir characteristics. These may include, forexample, formation depth, distance from a heater well, a richness of theformation hydrocarbons within the organic-rich rock formation, thedegree of heating, and/or a distance from a producer well.

It may be desirable for the developer of an oil shale field to monitorformation pressure during development. Pressure within a formation maybe determined at a number of different locations. Such locations mayinclude, but may not be limited to, at a wellhead and at varying depthswithin a wellbore. In some embodiments, pressure may be measured at aproducer well. In an alternate embodiment, pressure may be measured at aheater well. In still another embodiment, pressure may be measureddownhole of a dedicated monitoring well.

The process of heating an organic-rich rock formation to a pyrolysistemperature range not only will increase formation pressure, but willalso increase formation permeability. The pyrolysis temperature rangeshould be reached before substantial permeability has been generatedwithin the organic-rich rock formation. An initial lack of permeabilitymay prevent the transport of generated fluids from a pyrolysis zonewithin the formation. In this manner, as heat is initially transferredfrom a heater well to an organic-rich rock formation, a fluid pressurewithin the organic-rich rock formation may increase proximate to thatheater well. Such an increase in fluid pressure may be caused by, forexample, the generation of fluids during pyrolysis of at least someformation hydrocarbons in the formation.

Alternatively, pressure generated by expansion of pyrolysis fluids orother fluids generated in the formation may be allowed to increase. Thisassumes that an open path to a production well or other pressure sinkdoes not yet exist in the formation. In one aspect, a fluid pressure maybe allowed to increase to or above a lithostatic stress. In thisinstance, fractures in the hydrocarbon containing formation may formwhen the fluid pressure equals or exceeds the lithostatic stress. Forexample, fractures may form from a heater well to a production well. Thegeneration of fractures within the heated portion may reduce pressurewithin the portion due to the production of produced fluids through aproduction well.

Once pyrolysis has begun within an organic-rich rock formation, fluidpressure may vary depending upon various factors. These include, forexample, thermal expansion of hydrocarbons, generation of pyrolysisfluids, rate of conversion, and withdrawal of generated fluids from theformation. For example, as fluids are generated within the formation,fluid pressure within the pores may increase. Removal of generatedfluids from the formation may then decrease the fluid pressure withinthe near wellbore region of the formation.

In certain embodiments, a mass of at least a portion of an organic-richrock formation may be reduced due, for example, to pyrolysis offormation hydrocarbons and the production of hydrocarbon fluids from theformation. As such, the permeability and porosity of at least a portionof the formation may increase. Any in situ method that effectivelyproduces oil and gas from oil shale will create permeability in what wasoriginally a very low permeability rock. The extent to which this willoccur is illustrated by the large amount of expansion that must beaccommodated if fluids generated from kerogen are unable to flow. Theconcept is illustrated in FIG. 5.

FIG. 5 provides a bar chart comparing one ton of Green River oil shalebefore 50 and after 51 a simulated in situ, retorting process. Thesimulated process was carried out at 2,400 psi and 750° F. (about 400°C.) on oil shale having a total organic carbon content of 22 wt. % and aFisher assay of 42 gallons/ton. Before the conversion, a total of 16.5ft³ of rock matrix 52 existed. This matrix comprised 8.4 ft³ of mineral53, i.e., dolomite, limestone, etc., and 8.1 ft³ of kerogen 54 imbeddedwithin the shale. As a result of the conversion the material expanded to27.3 ft³ 55. This represented 8.4 ft³ of mineral 56 (the same number asbefore the conversion), 6.6 ft³ of hydrocarbon liquid 57, 9.4 ft³ ofhydrocarbon vapor 58, and 2.9 ft³ of coke 59. It can be seen thatsubstantial volume expansion occurred during the conversion process.This, in turn, increases permeability of the rock structure.

FIG. 6 illustrates a schematic diagram of an embodiment of surfacefacilities 70 that may be configured to treat a produced fluid. Theproduced fluid 85 produced from a subsurface formation, shownschematically at 84, though a production well 71. The produced fluid 85may include any of the produced fluids produced by any of the methods asdescribed herein. The subsurface formation 84 may be any subsurfaceformation including, for example, an organic-rich rock formationcontaining any of oil shale, coal, or tar sands for example. In theillustrative surface facilities 70, the produced fluids are quenched 72to a temperature below 300° F., 200° F., or even 100° F. This serves toseparate out condensable components (i.e., oil 74 and water 75).

Produced fluids 85 from in situ oil shale production contain a number ofcomponents which may be separated in the surface facilities 70. Theproduced fluids 85 typically contain water 78, noncondensablehydrocarbon alkane species (e.g., methane, ethane, propane, n-butane,isobutane), noncondensable hydrocarbon alkene species (e.g., ethene,propene), condensable hydrocarbon species composed of (alkanes, olefins,aromatics, and polyaromatics among others), CO₂, CO, H₂, H₂S, and NH₃.In a surface facility such as facility 70, condensable components 74 maybe separated from non-condensable components 76 by reducing temperatureand/or increasing pressure. Temperature reduction may be accomplishedusing heat exchangers cooled by ambient air or available water 72.Alternatively, the hot produced fluids may be cooled via heat exchangewith produced hydrocarbon fluids previously cooled. The pressure may beincreased via centrifugal or reciprocating compressors. Alternatively,or in conjunction, a diffuser-expander apparatus may be used to condenseout liquids from gaseous flows. Separations may involve several stagesof cooling and/or pressure changes.

In the arrangement of FIG. 6, the surface facilities 70 include an oilseparator 73 for separating liquids, or oil 74, from hydrocarbon vapors,or gas 76. The noncondensable vapor components 76 are treated in a gastreating unit 77 to remove water 78 and sulfur species 79. Heaviercomponents are removed from the gas (e.g., propane and butanes) in a gasplant 81 to form liquid petroleum gas (LPG) 80. The LPG 80 may be placedinto a truck or line for sale. Water 78 in addition to condensablehydrocarbons 74 may be dropped out of the gas 76 when reducingtemperature or increasing pressure. Liquid water may be separated fromcondensable hydrocarbons 74 via gravity settling vessels or centrifugalseparators. Demulsifiers may be used to aid in water separation.

The surface facilities also operate to generate electrical power 82 in apower plant 88 from the remaining gas 83. The electrical power 82 may beused as an energy source for heating the subsurface formation 84 throughany of the methods described herein. For example, the electrical power82 may be fed at a high voltage, for example 132 kV, to a transformer 86and let down to a lower voltage, for example 6600 V, before being fed toan electrical resistance heater element 89 located in a heater well 87in the subsurface formation 84. In this way all or a portion of thepower required to heat the subsurface formation 84 may be generated fromthe non-condensable portion 76 of the produced fluids 85. Excess gas, ifavailable, may be exported for sale.

In an embodiment, heating a portion of an organic-rich rock formation insitu to a pyrolysis temperature may increase permeability of the heatedportion. For example, permeability may increase due to formation ofthermal fractures within the heated portion caused by application ofheat. As the temperature of the heated portion increases, water may beremoved due to vaporization. The vaporized water may escape and/or beremoved from the formation. In addition, permeability of the heatedportion may also increase as a result of production of hydrocarbonfluids from pyrolysis of at least some of the formation hydrocarbonswithin the heated portion on a macroscopic scale.

Certain systems and methods described herein may be used to treatformation hydrocarbons in at least a portion of a relatively lowpermeability formation (e.g., in “tight” formations that containformation hydrocarbons). Such formation hydrocarbons may be heated topyrolyze at least some of the formation hydrocarbons in a selected zoneof the formation. Heating may also increase the permeability of at leasta portion of the selected zone. Hydrocarbon fluids generated frompyrolysis may be produced from the formation, thereby further increasingthe formation permeability.

Permeability of a selected zone within the heated portion of theorganic-rich rock formation may also rapidly increase while the selectedzone is heated by conduction. For example, permeability of animpermeable organic-rich rock formation may be less than about 0.1millidarcy before heating. In some embodiments, pyrolyzing at least aportion of organic-rich rock formation may increase permeability withina selected zone of the portion to greater than about 10 millidarcies,100 millidarcies, 1 Darcy, 10 Darcies, 20 Darcies, or 50 Darcies.Therefore, a permeability of a selected zone of the portion may increaseby a factor of more than about 10, 100, 1,000, 10,000, or 100,000. Inone embodiment, the organic-rich rock formation has an initial totalpermeability less than 1 millidarcy, alternatively less than 0.1 or 0.01millidarcies, before heating the organic-rich rock formation. In oneembodiment, the organic-rich rock formation has a post heating totalpermeability of greater than 1 millidarcy, alternatively, greater than10, 50 or 100 millidarcies, after heating the organic-rich rockformation.

In connection with the production of hydrocarbons from a rock matrix,particularly those of shallow depth, a concern may exist with respect toearth subsidence. This is particularly true in the in situ heating oforganic-rich rock where a portion of the matrix itself is thermallyconverted and removed. Initially, the formation may contain formationhydrocarbons in solid form, such as, for example, kerogen. The formationmay also initially contain water-soluble minerals. Initially, theformation may also be substantially impermeable to fluid flow.

The in situ heating of the matrix pyrolyzes at least a portion of theformation hydrocarbons to create hydrocarbon fluids. This, in turn,creates permeability within a matured (pyrolyzed) organic-rich rock zonein the organic-rich rock formation. The combination of pyrolyzation andincreased permeability permits hydrocarbon fluids to be produced fromthe formation. At the same time, the loss of supporting matrix materialalso creates the potential for subsidence relative to the earth surface.

In some instances, subsidence is sought to be minimized in order toavoid environmental or hydrogeological impact. In this respect, changingthe contour and relief of the earth surface, even by a few inches, canchange runoff patterns, affect vegetation patterns, and impactwatersheds. In addition, subsidence has the potential of damagingproduction or heater wells formed in a production area. Such subsidencecan create damaging hoop and compressional stresses on wellbore casings,cement jobs, and equipment downhole.

In order to avoid or minimize subsidence, it is proposed to leaveselected portions of the formation hydrocarbons substantiallyunpyrolyzed. This serves to preserve one or more unmatured, organic-richrock zones. In some embodiments, the unmatured organic-rich rock zonesmay be shaped as substantially vertical pillars extending through asubstantial portion of the thickness of the organic-rich rock formation.

The heating rate and distribution of heat within the formation may bedesigned and implemented to leave sufficient unmatured pillars toprevent subsidence. In one aspect, heat injection wellbores are formedin a pattern such that untreated pillars of oil shale are lefttherebetween to support the overburden and prevent subsidence.

In some embodiments, compositions and properties of the hydrocarbonfluids produced by an in situ conversion process may vary depending on,for example, conditions within an organic-rich rock formation.Controlling heat and/or heating rates of a selected section in anorganic-rich rock formation may increase or decrease production ofselected produced fluids.

In one embodiment, operating conditions may be determined by measuringat least one property of the organic-rich rock formation. The measuredproperties may be input into a computer executable program. At least oneproperty of the produced fluids selected to be produced from theformation may also be input into the computer executable program. Theprogram may be operable to determine a set of operating conditions fromat least the one or more measured properties. The program may also beconfigured to determine the set of operating conditions from at leastone property of the selected produced fluids. In this manner, thedetermined set of operating conditions may be configured to increaseproduction of selected produced fluids from the formation.

Certain heater well embodiments may include an operating system that iscoupled to any of the heater wells such as by insulated conductors orother types of wiring. The operating system may be configured tointerface with the heater well. The operating system may receive asignal (e.g., an electromagnetic signal) from a heater that isrepresentative of a temperature distribution of the heater well.Additionally, the operating system may be further configured to controlthe heater well, either locally or remotely. For example, the operatingsystem may alter a temperature of the heater well by altering aparameter of equipment coupled to the heater well. Therefore, theoperating system may monitor, alter, and/or control the heating of atleast a portion of the formation.

In some embodiments, a heater well may be turned down and/or off afteran average temperature in a formation may have reached a selectedtemperature. Turning down and/or off the heater well may reduce inputenergy costs, substantially inhibit overheating of the formation, andallow heat to substantially transfer into colder regions of theformation.

Temperature (and average temperatures) within a heated organic-rich rockformation may vary, depending on, for example, proximity to a heaterwell, thermal conductivity and thermal diffusivity of the formation,type of reaction occurring, type of formation hydrocarbon, and thepresence of water within the organic-rich rock formation. At points inthe field where monitoring wells are established, temperaturemeasurements may be taken directly in the wellbore. Further, at heaterwells the temperature of the immediately surrounding formation is fairlywell understood. However, it is desirable to interpolate temperatures topoints in the formation intermediate temperature sensors and heaterwells.

In accordance with one aspect of the production processes of the presentinventions, a temperature distribution within the organic-rich rockformation may be computed using a numerical simulation model. Thenumerical simulation model may calculate a subsurface temperaturedistribution through interpolation of known data points and assumptionsof formation conductivity. In addition, the numerical simulation modelmay be used to determine other properties of the formation under theassessed temperature distribution. For example, the various propertiesof the formation may include, but are not limited to, permeability ofthe formation.

The numerical simulation model may also include assessing variousproperties of a fluid formed within an organic-rich rock formation underthe assessed temperature distribution. For example, the variousproperties of a formed fluid may include, but are not limited to, acumulative volume of a fluid formed in the formation, fluid viscosity,fluid density, and a composition of the fluid formed in the formation.Such a simulation may be used to assess the performance of acommercial-scale operation or small-scale field experiment. For example,a performance of a commercial-scale development may be assessed basedon, but not limited to, a total volume of product that may be producedfrom a research-scale operation.

In the present disclosure, methods for heating a subsurface formationusing electrical resistance heating are provided. The resistive heat isgenerated primarily from electrically conductive material injected intothe formation from wellbores. An electrical current is then passedthrough the conductive material so that electrical energy is convertedto thermal energy. The thermal energy is transported to the formation bythermal conduction to heat the organic-rich rocks.

In one preferred embodiment of the current disclosure, conductivegranular material is used as a downhole heating element. The granularheating element is able to withstand geomechanical stresses createdduring the formation heating process. In this respect, the granularmaterial can readily change shape as needed without losing electricalconnectivity. Thus, methods are provided herein for applying heat to asubsurface formation wherein a granular material provides a resistivelyconductive pathway between electrically conductive members withinadjacent wellbores. However, non-granular conductive material such asconductive liquids that gel in place may be used.

FIG. 7 is a perspective view of a hydrocarbon production area 700. Thehydrocarbon production area 700 includes a subsurface formation 715. Thesubsurface formation 715 comprises organic-rich rock. In one instancethe organic-rich rock contains kerogen.

A substantially vertical fracture 712 has been created within thesubsurface formation 715. The fracture 712 is preferably hydraulicallyformed. The fracture 712 is propped with particles of an electricallyconductive material (not shown in FIG. 7). In accordance with themethods herein, an electrical current is sent through the conductivematerial to generate resistive heat within the formation 715.

FIG. 7 demonstrates the heat 710 emanating from the fracture 712. Inorder to provide electrical current and generate the heat 710, a voltage714 is applied across two adjacent wells 716 and 718. The fracture 712intersects the wells 716, 718 so that current travels from a first well(such as well 716), through fracture 712, and to a second well (such aswell 718).

Various ways of running current through the fracture 712 may bearranged. In the arrangement of FIG. 7, an AC voltage 714 is preferred.This is because AC voltage is more readily generated and minimizeselectrochemical corrosion as compared to DC voltage. However, any formof electrical energy, including without limitation, DC voltage, issuitable for use in the methods herein.

In the example of FIG. 7, a negative pole is set up at wellbore 716while a positive pole is set up at wellbore 718. Each wellbore 716, 718has a conductive member that runs to the subsurface formation 715 todeliver current. An amount of electrical current sufficient to generateheat necessary to cause pyrolysis of solid hydrocarbons is provided.Kinetic parameters for Green River oil shale, for example, indicate thatfor a heating rate of 100° C. (180° F.) per year, complete kerogenconversion will occur at a temperature of about 324° C. (615° F.). Fiftypercent conversion will occur at a temperature of about 291° C. (555°F.). Oil shale near the fracture will be heated to conversiontemperatures within months, but it is likely to require several years toattain thermal penetration depths required for generation of economicreserves across a subsurface volume.

Within the fracture 712, the granular material acts as a heatingelement. As electric current is passed through the fracture 712, heat710 is generated by resistive heating. Heat 710 is transferred bythermal conduction to the formation 715 surrounding the fracture 712. Asa result, the organic-rich rock within the formation 715 is heatedsufficiently to convert kerogen to hydrocarbons. The generatedhydrocarbons are then produced using well-known production methods.

In the arrangement of FIG. 7, the formation 715 is shown primarily alonga single vertical plane. Further, the heat 710 is shown emanating fromthe fracture 712 within that vertical plane. However, it is understoodthat the formation 715 is a three-dimensional subsurface volume, andthat the heat 710 will conduct across a portion of that volume.

As described above, FIG. 7 depicts a heating process using a singlevertical hydraulic fracture 712 and a pair of vertical wells 716, 718.In practice, a number of wellbore pairs 716, 718 would be completed withan intersecting fracture 712. However, other wellbore and completionarrangements may be provided. Examples include the use of horizontalwells and/or horizontal fractures. Commercial applications may involvemultiple fractures with the placement of multiple wells in a pattern orline-drive formation.

During the thermal conversion process, oil shale permeability is likelyto increase. This may be caused by the increased pore volume availablefor flow as solid kerogen is converted to liquid or gaseoushydrocarbons. Alternatively, increased permeability may result from theformation of fractures as kerogen converts to hydrocarbons and undergoesa substantial volume increase within a confined system. In this respect,if initial permeability is too low to allow release of the hydrocarbons,excess pore pressure will eventually cause fractures to develop. Theseare in addition to the hydraulic fractures initially formed duringcompletion of the wellbores 716, 718.

Referring now to FIGS. 8A and 8B, alternate arrangements 800A, 800B forheating a subsurface formation are illustrated. First, FIG. 8A shows ahydrocarbon production area 805A that includes a subsurface formation815. The subsurface formation 815 comprises organic-rich rock. Anexample of such an organic-rich rock is oil shale.

In the arrangement of FIG. 8A, a first plurality of wellbores 816 isprovided. Each wellbore 816 has a vertical portion and a deviated,substantially horizontal portion. Heat is once again delivered via aplurality of hydraulic fractures propped with particles of anelectrically conductive material. The fractures are shown at 812 and aresubstantially vertical. Each hydraulic fracture 812 is longitudinal (orruns along) the horizontal portion of the wells 816.

A separate second plurality of wells 818 is also provided in thehydrocarbon production area 800A. These wells 818 also have asubstantially vertical portion and a substantially horizontal portion.The substantially horizontal portions of the respective wells 818intersect respective fractures 812.

In the arrangement of FIG. 8A, a voltage is applied across pairs ofwells from the first plurality 816 and the second plurality 818 ofwells. The wells 816 in the first plurality of wells comprise negativepoles while the wells 818 in the second plurality of wells comprisepositive poles. Of course, the reverse could also be established. Avoltage 814 is applied across respective wells 816, 818 that penetratethe fractures 812. Once again, an AC voltage 814 is preferred. However,any form of electrical energy, including without limitation, DC voltage,is suitable for use in this invention.

The pairs of wells from the respective pluralities of wells 816, 818make up individual electrical circuits. The circuits are “completed” byplacing conductive granular material within the fractures 812. This, inturn, generates heat via resistive heating. This heat is transferred bythermal conduction to organic-rich rock within the subsurface formation815. As a result, the organic-rich rock is heated sufficiently toconvert kerogen contained in the subsurface formation 815 tohydrocarbons. The generated hydrocarbons are then produced throughproduction wells (not shown).

It is noted that the fractures 812 in FIG. 8A are vertical.Reciprocally, the intersecting portion of the second plurality ofwellbores 818 is horizontal. However, it is understood that thisarrangement could be reversed. This means that the fractures 812 may behorizontal while the intersecting portion of the second plurality ofwellbores 818 is vertical. In this latter arrangement it would not benecessary for the second plurality of wellbores 818 to be deviated. As apractical matter, the orientation of the fractures may be dependent onthe depth of the subsurface formation. For example, some Green River oilshale formations completed at or above 1,000 feet tend to createhorizontal fractures while formations completed below about 1,000 feettend to create vertical fractures. This, of course, is highly dependenton the actual location and the geomechanical forces at work.

FIG. 8B shows a second hydrocarbon production area 805B that includes asubsurface formation 815. The subsurface formation 815 comprisesorganic-rich rock which may include kerogen. In the arrangement of FIG.8B, a first plurality of wellbores 826 is provided. Each wellbore 826has a vertical portion and a deviated, substantially horizontal portion.Heat is once again delivered via a plurality of hydraulic fracturespropped with particles of an electrically conductive material. Thefractures are shown at 812 and are substantially vertical. Eachhydraulic fracture 812 is longitudinal (or runs along) the horizontalportion of the wells 826.

A separate second plurality of wells 828 is also provided in thehydrocarbon production area 800B. These wells 818 also have asubstantially vertical portion and a substantially horizontal portion.The substantially vertical portions of the respective wells 828intersect respective fractures 812.

In the arrangement of FIG. 8B, a voltage is applied across the firstplurality of wells 826 to one of the second plurality of wells 828. Thewells 826 in the first plurality of wells may comprise positive poleswhile the second well 828 may comprise a negative pole. Of course, thereverse could also be established. A voltage 824 is applied acrossrespective wells 826, 828 that penetrate the fractures 812. Once again,an AC voltage 824 is preferred. However, any form of electrical energy,including without limitation, DC voltage, is suitable for use in thisinvention.

The wells 826, 828 work together to make up individual electricalcircuits. The circuits are “completed” by placing conductive granularmaterial within the fractures 812. This, in turn, generates heat viaresistive heating. This heat is transferred by thermal conduction toorganic-rich rock within the subsurface formation 815. As a result, theorganic-rich rock is heated sufficiently to convert kerogen contained inthe subsurface formation 815 to hydrocarbons. The generated hydrocarbonsare then produced through production wells (not shown).

It is noted that the fractures 812 in FIG. 8B are vertical.Reciprocally, the intersecting portion of the second plurality ofwellbores 828 is horizontal. In the production area 800B, the horizontalportion of the second wellbores 828 intersect fractures 812 associatedwith more than one fracture 812 from more than one horizontal portion ofthe respective first wellbores 826.

In either of production areas 800A, 800B, various materials may be usedas the electrically conductive granular material. First, sands having athin metal coating may be employed. Second, composite metal and ceramicmaterials may be used. Third, carbon-based materials may be employed.Each of these examples is not only conductive but also serves as aproppant. Several additional conductive materials may be used which areless desirable as proppants. One example is a conductive cement. Also,green or black silicon carbide, boron carbide, or calcined petroleumcoke may be used as a proppant. It is also noted that combinations ofthe above materials may be utilized. In this respect, the electricallyconductive material is not required to be homogeneous, but may comprisea mixture of two or more suitable electrically conductive materials. Forexample, one or more conductive materials that serve as proppants may bemixed with one or more conductive materials that are non-proppants inorder to achieve a desired conductivity while operating within adesignated budget.

Regardless of the composition, the conductive material preferably meetsseveral criteria. First, the electrical resistivity of the granularmaterial under anticipated in situ stresses is preferably high enough toprovide resistive heating while also being low enough to conduct theplanned electric current from one well to another. The granular materialalso preferably meets the usual criteria for fracture proppants, e.g.,sufficient strength to hold the fracture open, and a low enough densityto be pumped into the fracture. Lastly, economic application of theprocess may set an upper limit on the cost of an acceptable granularmaterial.

In each of production areas 800A, 800B, production wells are provided.Illustrative production wells 840 are shown in FIG. 8B. The productionwells 840 are completed in the subsurface formation 815 to transporthydrocarbon fluids to the surface.

Example

In order to demonstrate the transmission of current through a fracturein an organic-rich rock in order to generate resistive heat, alaboratory test was conducted. Test results showed that resistiveheating using granular material successfully transforms kerogen in alaboratory specimen of rock into producible hydrocarbons.

Referring now to FIG. 9 and FIG. 10, a core sample 900 was taken from akerogen-containing subterranean formation. The core sample 900 was athree-inch long plug of oil shale with a diameter of 1.39 inches. Thebedding of the oil shale was perpendicular to the core 900 axis. Asillustrated in FIG. 9, core sample 900 was cut into two portions 932 and934. Upper face 936 lies on portion 932 while lower face 938 correspondsto portion 934.

A tray 935 having a depth of about 0.25 mm ( 1/16 inch) was milled intosample portion 932 and a proxy proppant material 910 comprising #170cast steel shot having a diameter of about 0.1 mm (0.02 inch) was placedin the tray 935. As illustrated, a sufficient quantity of conductiveproppant material 910 to substantially fill tray 935 was used.

Electrodes 937 were placed at opposing ends of portion 932. Theelectrodes 937 extend from outside the bounds of the core 900 intocontact with proppant material 910.

As shown in FIG. 10, sample portions 932 and 934 were placed in contactas if to reconstruct the core sample 900. The core 900 was then placedin a stainless steel sleeve 940 with portions 932 and 934 being heldtogether with three stainless steel hose clamps 942.

The hose clamps 942 were tightened to apply stress to the proxy proppant(seen in FIG. 9), just as the proppant 910 would be required to supportin situ stresses in a real application. The resistance betweenelectrodes 937 was measured at 822 ohms before any electrical currentwas applied.

A small hole (not shown) was drilled in one half of the sample 900 inorder to accommodate a thermocouple. The thermocouple was used tomeasure the temperature in the core sample 900 during heating. Thethermocouple was positioned roughly mid-way between tray 935 and theouter diameter of core sample 900.

The clamped core sample 900 was placed in a pressure vessel (not shownin the Figures) with a glass liner. The purpose of the glass liner wasto collect hydrocarbons generated from the heating process. The pressurevessel was equipped with electrical feeds. The pressure vessel wasevacuated and charged with Argon at 500 psi to provide a chemicallyinert atmosphere for the experiment. Electrical current in the range of18 to 19 amps was applied between electrodes 937 for 5 hours. Thethermocouple in core sample 900 measured a temperature of 268° C. afterabout one hour, and thereafter tapered off to about 250° C. The hightemperature reached at the location of tray 935 was inferred to be fromabout 350° C. to about 400° C.

After the experiment was completed and the core sample 900 had cooled toambient temperature, the pressure vessel was opened. 0.15 ml of oil wasrecovered from the bottom of the glass liner in which the experiment wasconducted. The core sample 900 was removed from the pressure vessel, andthe resistance between electrodes 937 was again measured. Thispost-experiment resistance measurement was 49 ohms.

During the heating period the power consumption, electrical resistanceand temperature at the thermocouple embedded in the sample 900 wererecorded. FIG. 11 provides graphs showing power consumption 1112,temperature 1122, and electrical resistance 1132 recorded as a functionof time.

First, FIG. 11 includes chart 1110. Chart 1110 has ordinate 1112representing the electrical power, in watts, consumed during theexperiment. Chart 1110 also has abscissa 1114, which shows the elapsedtime in minutes for the experiment. The total time on the abscissa 1114was 5 hours (300 minutes). It can be seen from chart 1110 that after onehour, power applied to the core sample 900 ranged between 50 and 60watts.

Next, FIG. 11 includes chart 1120. Chart 1120 has ordinate 1122representing the temperature in degrees Celsius measured at thethermocouple in the core sample 900 (FIGS. 9 and 10) throughout theexperiment. Chart 1120 also has abscissa 1124 which shows the elapsedtime in minutes during the experiment. Again, the total time is 5 hours.It is noted that the temperature 1122 reached a maximum value of 268 Cduring the experiment. From this value it can be inferred that thetemperature along the tray 935 should have reached a value of 350-400 C.This value is sufficient to cause pyrolysis.

Finally, FIG. 11 includes chart 1130. Chart 1130 has ordinate 1132representing the resistance in ohms measured between electrodes 937(FIGS. 9 and 10) during the experiment. Chart 1130 also has abscissa1134 which again shows the elapsed time in minutes during theexperiment. Only resistance measurements made during the heatingexperiment are included in chart 1130. Of interest, after the initialheat-up of the sample 900, the resistance 1132 remained relativelyconstant between 0.15 and 0.2 ohms. At no time during the experiment wasa loss of electrical continuity observed. The pre-experiment andpost-experiment resistance measurements (822 and 49 ohms) are omitted.

After the core sample 900 cooled to ambient temperature, it was removedfrom the pressure vessel and disassembled. The conductive proppantmaterial 910 was observed to be impregnated in several places withtar-like hydrocarbons or bitumen, which were generated from the oilshale during the experiment. A cross section was taken through a crackthat developed in the core sample 900 due to thermal expansion duringthe experiment. A crescent shaped section of converted oil shaleadjacent to the proxy proppant 910 was observed.

Returning now to FIGS. 7, 8A and 8B, connections to the fracture heatingelement may be implemented in various ways. In each of thesearrangements, connection points are provided between conductive metaldevices along adjacent wellbores to intermediate conductive granularmaterial within a fracture. Such point connections are made alongvertical wellbores (FIG. 7), at the heel of a horizontal wellboreportion (FIG. 8A), at the toe of a horizontal wellbore portion (FIG.8B).

A concern arises with respect to each of these resistive heater-wellcompletion arrangements 700, 800A, 800B. This concern relates to thepotential for very high electric current density in the area where thewellbores intersect the conductive granular material. This concernapplies to any of the completion arrangements of FIGS. 7, 8A and 8B.

Electric current is an average quantity that describes the flow ofelectrons along a flow path. The SI unit for quantity of electricity orelectrical charge is the coulomb. The coulomb is defined as the quantityof charge that has passed through the cross-section of an electricalconductor carrying one ampere within one second. The symbol Q is oftenused to denote a quantity of electricity or charge.

Electric current may have a current density representing the electriccurrent per unit area of cross section. In SI units, this may beexpressed as Amperes/m². A current density vector may be denoted as iand described mathematically:

i=nqv_(d)=Dv_(d)

where

-   -   i=current density vector (amperes/m²)    -   n=particle density in count per volume (m⁻³);    -   q=individual particles' charge (coulombs);    -   D=charge density (Coulombs/m³), or n q; and    -   v_(d)=particles' average drift velocity (m/sec).

The presence of excessive current density at electrical contact pointsdownhole may result in an inconsistent heat distribution within asubsurface formation 715 or 815. In this respect, significant heatingmay occur primarily near the intersection of the wellbores with thegranular material, leaving inadequate resistive heating within theremainder of the subsurface formation.

To address this issue, it is proposed herein to place a second type ofgranular material at or near the contact points downhole. This secondtype of granular material has an electrical conductivity that isdifferent from the conductive granular material in the bulk of thefracture. Such an arrangement may operate in either of two ways. If thesecond material has a higher conductivity, it can operate by loweringthe voltage drop across a contact point having a high current density.In this instance the high current density still exists but it does notlead to excessive local heat generation. Alternatively, if the secondmaterial has a much lower (even zero) conductivity, it can operate bychanging the dominant current pathways to eliminate the area of highcurrent density.

It is preferred to employ the first option wherein the second conductivematerial has a significantly higher conductivity than the conductivematerial in the bulk of the fracture. Preferably, the conductivity ofthe second conductive material is about ten to 100 times higher than theconductivity of the granular material. In one aspect, the bulk of afracture is filled with calcined coke, while the conductive materialimmediately at the connection point comprises powdered metals, graphite,carbon black, or combinations thereof. Examples of powdered metalsinclude powdered copper and steel.

For example, in an exemplary embodiment of the first option, e.g., wherethe second conductive material has a significantly higher conductivitythan the conductive material in the bulk of the fracture, the presentinventors have determined that granular mixtures of graphite with up to50% by weight cement produce suitable resistivities. The presentinventors have determined that mixtures within this compositional rangeare also 10-100 times more conductive than the granular proppantmaterial. The present inventors have also determined that compositionswith cement content above 50% by weight increase mixture resistivityabove a preferred resistivity range. Water, which may be added tocontrol the viscosity of the granular mixture, is typically added to thegranular mixture to aid in adequate distribution of the conductivematerial into a proppant filled fracture. The pack thickness of theinjected granular material may also be controlled by addition orsubtraction of water to the granular mixture, e.g., more water willproduce a thinner and more widely dispersed pack upon injection.Accordingly, the present inventors have determined that the granularmixtures within the aforementioned compositional ranges are conductiveenough to not generate hot spots if used as the above-described secondconductive material.

For example, an exemplary composition for the above-described secondconductive material that has been determined to be suitable for use inthe vicinity of electrical contact points downhole includes 10 ggraphite (75% dry wt.), 3.3 g Portland cement (25% wt.), and 18 g water.In order to determine the differences in bulk resistivity between afirst conductive material (representative of material within thefracture and intermediate to any electrical connections) and a secondconductive material (the aforementioned mixture of 10 g graphite, 3.3 gPortland cement, and 18 g of water were injected between two marbleslabs subjected to various loads and stress cured for 64 hours. Theoverall pack thickness of the second conductive material achieved wasapproximately 0.01″ to approximately 0.028.″ The resistivity of thesecond conductive material was approximately 0.1638 ohm cm, which wasapproximately 10-100 times more conductive than the surroundingproppant. The resistivity of two representative samples of the secondconductive material are shown below under various loads in Table I.Sample A included a 25% by dry weight cement and 75% by dry weightgraphite, and sample B included a 50% by dry weight cement and 50% bydry weight graphite. The resistivity of sample A was consistently lowerthan that of the second sample across all subjected loads. Whileadequate resistivities were achieved in both samples, a preferredembodiment would include a mixture containing cement of less than orequal to 50% by weight (dry), and equal to or greater than 50% by weightof graphite, and more preferably a mixture containing between 25-50% byweight (dry) of cement and 50-75% by weight (dry) of graphite, oranother electrically conductive material such as granular metal, metalcoated particles, coke, graphite, and/or combinations thereof

TABLE I Resistivity (ohm cm) load lbs load lbs load lbs load lbs loadlbs load lbs Sample ID 0 lbs 50 lbs 100 lbs 150 lbs 200 lbs 250 lbs A0.11 0.09 0.08 0.07 0.07 0.07 B 0.45 0.19 0.14 0.12 0.10 0.10

In order to understand the utility of using a strategically placedgranular material at the connection point, it is helpful to considermathematical concepts describing the flow of current through a body.FIG. 12 demonstrates a flow of current through a fracture plane 1200 ina geological formation. Arrows demonstrate current increments in the xand y directions for partial derivative equations. Arrow i_(x) indicateselectrical current flowing in the x direction while arrow i_(y)indicates electrical current flowing in they direction. Reference “t”indicates the thickness of the fracture 1200 at a point (x, y).

In fracture plane 1200, current moves in the x direction from a firstpoint location x to a second location x+dx. The current value changesfrom i_(x)+di_(x). Similarly, current moves in the y direction from afirst point location y to a second point location y+dy. The currentvalue changes from i_(y) to di_(y). If current enters or leaves thefracture at the location (x, y), this source term may be written as Q(x,y) and has units of Amperes/m². This represents a source of current at apoint in a fracture.

As current moves charge is conserved. Charge conservation is theprinciple that electric charge can neither be created nor destroyed; thequantity of electric charge is always conserved. According to the theoryof conservation of charge, the total electric charge of an isolatedsystem remains constant regardless of changes within the system itself.Conservation of charge may be expressed mathematically using partialderivative equations:

${\frac{\partial\left( {ti}_{x} \right)}{\partial x} + \frac{\partial\left( {ti}_{y} \right)}{\partial y}} = {Q\left( {x,y} \right)}$

wherein:

-   -   i_(x)=current in the x direction within the reservoir    -   i_(y)=current in the y direction within the reservoir    -   t=thickness of a section of a reservoir        -   Q(x, y)=source of current at a point in a fracture

By Ohm's law:

${i_{x} = {\frac{- 1}{p}\frac{\partial V}{\partial x}}};{i_{y} = {\frac{- 1}{p}\frac{\partial V}{\partial y}}}$

wherein:

-   -   ρ=resistivity of material in a reservoir    -   V=voltage of material

As noted, high heat generation may take place at the point connectionsbetween the metal conductors and the conductive granular material. Amathematical process has been developed for estimating the heatgeneration distribution for a fracture having resistive heat. This, inturn, allows for modeling of alternate methods for reducing heatgeneration at the downhole connection points.

A first step in this mathematical process is to provide a mapping of theproduct of conductivity and thickness. This may be expressed as:

$\frac{t}{\rho} = {{conductivity} \times {thickness}}$

As will be graphically demonstrated below, this first mapping step isconducted across the plane of the fracture.

A next step in the process is to provide a mapping of the input andoutput current. These currents may be represented as:

Q(x,y)

As will be graphically demonstrated below, this second mapping step isagain conducted across the plane of the fracture.

The two mapping steps provide input maps. After the maps are created, anequation governing voltage can be solved based upon a voltagedistribution in the fracture. An equation governing voltage may beexpressed:

${{\frac{\partial}{\partial x}\left( {\frac{t}{\rho}\frac{\partial V}{\partial x}} \right)} + {\frac{\partial}{\partial y}\left( {\frac{t}{\rho}\frac{\partial V}{\partial y}} \right)}} = {- {Q\left( {x,y} \right)}}$

Once the voltage distribution has been calculated, a heatingdistribution in the fracture can be calculated. This is done from a heatgeneration equation, as follows:

${h\left( {x,y} \right)} = {- {t\left( {{i_{x}\frac{\partial V}{\partial x}} + {i_{x}\frac{\partial V}{\partial y}}} \right)}}$

Using the mathematical process described above, three different examplesor “calculation scenarios” are provided herein to consider the problemof high current density around the power connections. The calculationscenarios involve an approximately 90 foot by 60 foot fracture filledwith calcined coke as the granular conductant. The fracture is 0.035inches thick at its center, with its thickness decreasing toward itsperiphery. Connections to the granular material within the fracture aremade with steel plates. The current into and out of the fracture isintroduced through these plates.

Various figures are provided in connection with the three calculationscenarios. In some instances the figures include a legend which providesthe resistivities of the materials used in the three calculations. Inthe legends, ρ_(coke) refers to the resistivity of the bulk proppantmaterial used in all three scenarios; ρ_(connector) refers to theresistivity of the more conductive material used around the connectionsin the second scenario; and ρ_(steel), refers to the resistivity of thesteel plates. Of course, this is merely illustrative as the plates couldbe fabricated from conductive materials other than steel.

Simulation No. 1

As noted, a solution to the problem of high current density leading tohot spots in the formation is implemented by placing a first type ofgranular material in the immediate vicinity of the connection betweenthe conductors and the conductive granular material. To demonstrate theefficacy of this approach, a first simulation was conducted in whichthere was no intermediate material, meaning that the conductive granularmaterial was homogeneous. Direct contact is provided between the steelplates and the homogeneous conductive material.

The results of the first simulation are demonstrated in FIGS. 13 through17. First, FIG. 13 provides a thickness-conductivity map 1300 showing aplan view of a simulated fracture. The fracture is shown at 1310. Thefracture 1310 is filled with a conductive proppant. In this simulation,coke is used as the conductive proppant. The coke has a resistivity(indicated at ρ_(coke)) of 0.001 ohm-m.

Two steel plates are shown at 1320 within the fracture 1310. Theserepresent a left plate 1320L and a right plate 1320R. The plates 1320are modeled as four foot long plates that are three inches wide by½-inch thick. The coke surrounds and immediately contacts each of thesteel plates 1320. The steel plates 1320 serve to deliver current in thefracture 1310 and through the coke. The resistivity of the plates 1320(indicated at ρ_(steel)), is 0.0000005 ohm-m.

The map 1300 is gray-scaled to show the value of conductivity of thegranular proppant multiplied by its thickness across the map 1300. Thismeans that the product of conductivity and thickness (t/ρ) for thefracture 1310 is mapped across a plan view of the fracture 1320. Thevalues are measured in amps/volt. The scale starts at 0-2,000 amps/volt,and goes to 30,000-32,000 amps/volt. At this scale, the proppant in thefracture 1310 entirely falls within the 0-2,000 amps/volt range. Statedanother way, the thickness-conductivity product is consistent between 0and 2,000 amps/volt.

The plates 1320 are highly conductive. Therefore, thethickness-conductivity of the plates 1320 shows in the 30,000-32,000amps/volt range.

FIG. 14 is another view of the thickness-conductivity map 1300 of FIG.13. The map 1300 is gray-scaled in finer increments of conductivitymultiplied by thickness to distinguish variations in proppantconductivity-thickness within the fracture 1310. The scale starts at0.000-0.075 amps/volt, and goes to 1.125-1.200 amps/volt. At this scale,variations in the thickness-conductivity product within the fracture1310 become evident. At an outer ring, the thickness-conductivityproduct is within the smallest range of the scale—0.000-0.075 amps/volt.As one moves inward towards the center of the fracture 1310, concentricbands of increasing thickness-conductivity product are seen. At thecenter, the thickness-conductivity value is about 0.825 to 0.900amps/volt.

It is noted that the conductivity of the coke within the fracture 1310is constant. Therefore, the demonstrated variations are attributed tofracture thickness variations. The fracture 1310 is thin at the outeredge, and becomes increasingly thick towards its center. This tends tosimulate actual fracture geometry.

The two steel plates 1320 are also seen in FIG. 14. As noted inconnection with FIG. 13, the thickness-conductivity product of theplates 1320 falls in the 30,000-32,000 amps/volt range. Therefore, theplates 1320 are off of the chart in FIG. 13 and simply show up as beingwhite.

Next, FIG. 15 provides a current source map 1300. In this instance, themap 1300 shows movement of current into and out of the fracture 1310.More specifically, FIG. 15 shows the input and output current for thefirst simulation. As indicated, the total current into and out of thefracture 1310 is one ampere. In one aspect, current goes into the plate1320L on the left, and leaves through the plate 1320R on the right.

FIG. 15 includes a scale for current, in units of amps/ft². The scaleruns from −1.20-−1.05 to 1.05-1.20. In between, the scale moves through−0.15-0.00 and 0.00-0.15. It can be seen that the current entering andleaving the fracture 1310 is 0.0 amps/ft² except at the two steel plates1320.

FIG. 16 demonstrates a calculated voltage distribution in the fracture1310 from the one ampere of total current. Lines with arrows areprovided to indicate the electrical current flow, which follows thelocal voltage gradient. As indicated, the total resistance of thefracture 1310 between the two pieces of steel 1320 is 2.71 Ohms.

A scale is provided in FIG. 16 measured in volts. The scale moves from−1.6-−1.4 to 1.4-1.6. In between, the scale moves through −0.2-0.0 and0.0-0.2 volts. It can be seen that strongly negative voltage valuesexist immediately at the right plate 1320R, and strongly positivevoltage values exist immediately at the left plate 1320L. It can also beseen that there is a higher concentration of current at the steel plates1320.

Finally, FIG. 17 demonstrates the resulting heating distribution in thefracture 1310 from the first simulation. The units of the map 1300 areWatts/ft². A gray-scale is provided indicating values from 0 up to 16Watts/ft2. As can be seen, the heat distribution in the map 1300 shows atotal heat input of 1,000 Watts. 60 of the 1,000 Watts (6% of the heat)are generated within one foot of the ends of the plates 1320L, 1320R.

The heat generation in the simulated fracture 1310 declines rapidly awayfrom the steel plates 1320. This indicates that much energy was lost atthe plates 1320 without generating sufficient heat to pyrolyze solidformation hydrocarbons that would otherwise reside in the formation. Sixpercent of the heat was generated in just 0.14% of the fracture area1310. As a result, excessive heating was demonstrated to occur in theimmediate vicinity of the steel plates 1320. Therefore, a modificationis desired to disperse heat away from the plates 1320.

Simulation No. 2

A second simulation was conducted wherein an “intermediate material” wasplaced between the steel plates and the surrounding calcined coke. Theintermediate material was a highly conductive material that was placedaround the conductive connections. The “intermediate material” wassimulated to have an electrical conductivity 100 times that of thecalcined coke, or a resistivity of 0.00001 Ohm-Meters. As will be shown,this eliminated the high voltage drop across the area of high currentdensity around the connection points, effectively eliminating theexcessive heating around the connection points.

The results of the second simulation are demonstrated in FIGS. 18through 23. First, FIG. 18 provides a thickness-conductivity map 1800showing a plan view of a simulated fracture. The fracture is shown at1810. The fracture 1810 is again filled with a conductive proppant. Inthis simulation, coke is used as a primary conductive proppant. The cokeagain has a resistivity (indicated at ρ_(coke)) of 0.001 ohm-m.

Two steel plates are shown at 1820 within the fracture 1810. Theserepresent a left plate 1820L and a right plate 1820R. The coke surroundseach of the steel plates 1820. The steel plates 1820 serve to delivercurrent in the fracture 1810 and through the coke.

In this second simulation the coke does not immediately contact thesteel plates 1820; rather, a connecting granular material is used aroundthe plates 1820. The resistivity of the connector material (indicated atρ_(connector)) is 0.00001 ohm-m.

The map 1800 is gray-scaled to show the value of conductivity of theconductive granular proppants 1820 multiplied by its thickness atvarious locations across the map 1800. This means that the product ofconductivity and thickness (t/ρ) for the fracture 1810 is mapped acrossa plan view of the fracture 1820. The values are measured in amps/volt.The scale starts at 0-2,000 amps/volt, and goes to 30,000-32,000amps/volt. At this scale, the proppants in the fracture 1810 entirelyfall within the 0-2,000 amps/volt range. Stated another way, thethickness-conductivity product is consistent between 0 and 2,000amps/volt.

The map 1800 of FIG. 18 has been scaled to distinguish between theconductive granular proppant in the fracture 1810, and the two steelplates 1820 that make up the electrical connection. The legend in FIG.18 gives the resistivities of the materials used in the secondsimulation. The ρ_(coke) refers to the resistivity of the bulk proppantmaterial; the ρ_(connector) refers to the resistivity of the highlyconductive material used immediately around the plates 1820L, 1820R;and, the ρ_(steel), refers to the resistivity of the steel plates 1820.

The plates 1820 are once again modeled as four-foot-long,three-inch-wide, and ½-inch-thick plates. The plates 1820 are highlyconductive, with the thickness-conductivity of the plates 1820 showingin the 30,000-32,000 amps/volt range. The plates 1820 show up as beingblack.

FIG. 19 is another view of the thickness-conductivity map 1800 of FIG.18. The map 1800 is gray-scaled in finer increments of conductivitymultiplied by thickness to distinguish variations in proppantconductivity-thickness within the fracture 1810. The scale starts at0.00-2.50 amps/volt, and goes to 37.50-40.00 amps/volt. At this scale,variations in the thickness-conductivity product between the primarycoke proppant and the connector proppant become evident. Theconductivity-thickness product across most of the fracture 1800 iswithin the smallest range of the scale—0.00-2.50 amps/volt. However,concentric rings of proppant having a higher conductivity-thicknessproduct are visible around the plates 1820L, 1820R. Immediately adjacentthe plates 1820L, 1820R, the conductivity-thickness product is as highas 17.5 to 20.0 amps/volt. The rings dissipate away from the plates1820L, 1820R to about 7.5 to 10.0 amps/volt before dropping to thelowest range of 0.00 to 2.50 amps/volt within the coke.

FIG. 20 is another view of the thickness-conductivity map 1800 of FIG.18. The map 1800 is gray-scaled in still further finer increments ofconductivity multiplied by thickness to distinguish variations inproppant conductivity-thickness within the primary proppant. The scalestarts at 0.000-0.075 amps/volt, and goes to 1.125-1.200 amps/volt. Theconductivity-thickness product across the fracture 1810 is approximately0.000 to 0.075 at the edge of the fracture 1810, and increases to about0.675 to 0.750 at the center of the fracture 1810. However, concentricrings of proppant having a higher conductivity-thickness product areagain visible. These rings show up white and are off the scale as theirconductivity exceeds the highest range of 1.125 to 1.200.

In FIG. 20 the plates 1820 cannot be distinguished from the intermediateproppant because they are “off the chart” as well, meaning theconductivity-thickness product is high.

It is noted that the conductivity of the coke within the fracture 1810is constant. Therefore, the demonstrated variations inconductivity-thickness product seen in FIG. 20 are attributed tofracture thickness variations. The fracture 1810 is thin at the outeredge, and becomes increasingly thick towards its center. This tends tosimulate actual fracture geometry.

Next, FIG. 21 provides a current source map 1800. In this instance, themap 1800 shows movement of current into and out of the fracture 1810.More specifically, FIG. 21 shows the input and output current for thesecond simulation. As indicated, the total current into and out of thefracture 1810 is one ampere. In one aspect, current goes into the plate1820L on the left, and leaves through the plate 1820R on the right. Thecurrent entering and leaving the fracture 1810 is zero, except at thesteel plates 1820R, 1820L.

FIG. 21 includes a scale for current, in units of amps/ft². The scaleruns from −1.20-−1.05 to 1.05-1.20. In between, the scale moves through−0.15-0.00 and 0.00-0.15. It can be seen that the current entering andleaving the fracture 1810 is 0.0 amps/ft² except at the two steel plates1820.

FIG. 22 demonstrates a calculated voltage distribution in the fracture1810 from the one ampere of total current. Lines with arrows areprovided to indicate the electrical current flow, which follows thelocal voltage gradient. As indicated, the total resistance of thefracture 1810 between the two plates 1820 is 1.09 Ohms, indicating thatthe higher conductivity material around the plates 1820 has decreasedthe overall resistance in the fracture relative to the map 1300 of FIG.16.

A scale is provided in FIG. 22 measured in volts. The scale moves from−0.64-−0.56 to 0.56-0.64. In between, the scale moves through −0.08-0.0and 0.0-0.08 volts. These ranges are lower than in the corresponding map1300 of FIG. 16. This is because total resistance in fracture plane 1810is lower.

It can be seen in FIG. 22 that negative voltage values exist immediatelyat the right plate 1820R, and positive voltage values exist immediatelyat the left plate 1820L. Of interest, current is still focused in thevicinity of the plates 1820, meaning that there is a higherconcentration of current at the steel plates 1820. However, the currentpathways can be seen to bend as they enter and leave the higherconductivity areas around the plates 1820.

Finally, FIG. 23 demonstrates the resulting heating distribution in thefracture 1810 from the simulation. The units of the map 1800 areWatts/ft². A gray-scale is provided indicating values from 0.0-0.2 up to3.0-3.2 Watts/ft². As can be seen, the heat distribution in the map 1800shows a total heat input of 1,000 Watts. However, only 3.3 of the 1,000Watts (0.33% of the heat) are generated within 1 foot of the ends of theconnecting plates 1820L, 1820R. This is a substantial reduction inlocalized heat generation over the first simulation demonstrated in FIG.17, proving a more uniform heating of the fracture 1810.

It is again noted that moderate heat is indicated at the respective endsof the plates 1820L, 1820R. However, these heat areas do not reflectextensive heating within the overall fracture 1810 and provide no causefor concern.

Simulation No. 3

Next, a third simulation was conducted wherein a non-conductive materialwas used as the connecting granular material. The non-conductivematerial was specifically placed at the ends of the simulated steelplates. The non-conductive material operates to redirect current in theformation to mitigate excessive heating around the steel connections.This is another alternative method for eliminating the high heating inthe area of high current density around the plates, effectively reducingthe excessive heating experienced in the first simulation so that thefracture receives a more uniform heat distribution.

The results of the third simulation are demonstrated in FIGS. 24 through28. First, FIG. 24 provides a conductivity map 2400 showing a plan viewof a simulated fracture. The fracture is shown at 2410. The fracture2410 is again filled with a conductive proppant. In this simulation,coke is used as a primary conductive proppant. The resistivity of thecoke (indicated at ρ_(coke)) is 0.001 ohm-m.

Two steel plates are shown at 2420 within the fracture 2410. Theserepresent a left plate 2420L and a right plate 2420R. The coke surroundseach of the steel plates 2420. The steel plates 2420 serve to delivercurrent in the fracture 2410 and through the coke.

In this third simulation the coke does not immediately contact all ofthe steel plates 2420; rather, an intermediate granular material is usedaround the plates 2420 with coke contacting the plates 2420 only atrespective ends. In this instance, the granular material issubstantially non-conductive. Thus, the resistivity of the coke is 0.001ohm-m, while the resistivity of the granular connector material(indicated at ρ_(connector)) is essentially infinite.

The map 2400 is gray-scaled to show the value of conductivity of theconductive granular proppant multiplied by its thickness at variouslocations across the map 2400. This means that the product ofconductivity and thickness (t/ρ) for the fracture 2410 is mapped acrossa plan view of the fracture 2420. The values are measured in amps/volt.

The map 2400 of FIG. 24 has been scaled to distinguish between the cokein the fracture 2410, and the two steel plates 2420 that make up theelectrical connection. The legend in FIG. 24 gives the resistivities ofthe materials used in all the third simulation. The ρ_(coke), refers tothe resistivity of the bulk proppant material; the ρ_(connector) refersto the resistivity of the non-conductive granular material used aroundthe connectors 2420L, 2420R in the third simulation; and, the ρ_(steel),refers to the resistivity of the steel plates 2420. The scale starts at0-2,000 amps/volt, and goes to 30,000-32,000 amps/volt. At this scale,the resistivity values for the proppant in the fracture 2410 (ρ_(coke))entirely fall within the 0-2,000 amps/volt range. Stated another way,the thickness-conductivity product is consistent between 0 and 2,000amps/volt.

In the third simulation, the plates 2420 are modeled as 27 feet long, 3inches wide, and ½-inch thick. Compared to the four-foot plates 1820used in the second simulation, the plates 2420 of the third simulationare very long. This is because the connecting granular material used inthe third simulation is substantially non-conductive. The longer plates2420 provide additional surface area through which current may travelinto the fracture 2410. The plates 1820 are highly conductive, with thethickness-conductivity of the plates 2420 showing in the 30,000-32,000amps/volt range. The current into and out of the fracture 2410 isintroduced through the plates 2420.

FIG. 25 is another view of the conductivity map 2400 of FIG. 24. The map2400 is gray-scaled in finer increments of conductivity multiplied bythickness to distinguish variations in proppant conductivity-thicknesswithin the fracture 2410. The scale starts at 0.000-0.075 amps/volt, andgoes to 1.125-1.200 amps/volt. The conductivity-thickness product acrossthe fracture 2410 is approximately 0.000 to 0.075 at the edge of thefracture 2410, and increases to about 0.675 to 0.750 at the center ofthe fracture 1810. However, concentric rings of substantiallynon-conductive proppant appear at ends of the plates 2420L, 2420R. Theserings show up almost white as their conductivity is zero.

The map 2400 of FIG. 25 has been scaled to distinguish variations inconductivity-thickness in the coke-filled bulk of the fracture 2410. Thecoke proppant is indicated at 2425. The conductivity of the cokeproppant 2425 within the fracture 2410 is constant. Therefore, thedemonstrated variations in conductivity-thickness product are attributedto fracture thickness variations. The fracture 2410 is thin at the outeredge, and becomes increasingly thick towards its center. This tends tosimulate actual fracture geometry.

FIG. 25 also shows where non-conductive material (t/ρ=0) has beenemplaced around the ends of the steel plates 2420L, 2420R. Thenon-conductive granular material is indicated at 2427. Thisnon-conductive material 2427 interrupts the flow of current from theplates 2420L, 2420R to the bulk proppant 2425.

The plates 2420 are also visible in FIG. 25. The extremely highconductivity plates 2420 show up in FIG. 25 as white lines, indicatingan off-scale value.

Next, FIG. 26 provides a current source map 2400. In this instance themap 2400 shows movement of current into and out of the fracture 2410.More specifically, FIG. 26 shows the input and output current for thethird simulation. As indicated, the total current into and out of thefracture 2410 is one ampere. In one aspect, current goes into theconnector 2420L on the left, and leaves through the connector 2420R onthe right. The current entering and leaving the fracture 2410 is zeroexcept at the steel plates 2420R, 2420L.

It is noted that the 27-foot length of the respective connectors 2420Land 2420R appears abbreviated in the view of FIG. 26. This is becausecurrent is only being supplied near the ends of the plates 2420. It isnoted that the exposed portion in each of plate 2422L and 2422R isshorter in FIG. 26 than in FIG. 25. This is indicative of where thecurrent has been applied.

FIG. 26 includes a scale for current, in units of amps/ft². The scaleruns from −1.20-−1.05 to 1.05-1.20. In between, the scale moves through−0.15-0.00 and 0.00-0.15. It can be seen that the current entering andleaving the fracture 2410 is 0.0 amps/ft² except at a portion of the twosteel plates 2420 that are in contact with the conductive proppant.

FIG. 27 demonstrates a calculated voltage distribution in the fracture2410 from the one ampere of total current. Lines with arrows areprovided to indicate the electrical current flow, which follows thelocal voltage gradient. As indicated, the total resistance of thefracture 2410 between the two plates 2420 is 2.39 Ohms. This is slightlyless than the 2.71 Ohms prevalent in FIG. 16 from the first simulation.Thus, while the non-conductive connecting material 2427 around the endsof the plates 2420 should increase the resistance relative to the map1300 of FIG. 16, the steel plates are much longer, and their impact isto decrease the overall resistance of the fracture 2410.

A scale is provided in FIG. 27 measured in volts. The scale moves from−1.28-−1.12 to 1.12-1.28. In between, the scale moves through −0.16-0.0and 0.0-0.16 volts.

It can be seen in FIG. 27 that negative voltage values exist immediatelyat the right connector 2420R, and positive voltage values existimmediately at the left connector 2420L. Of interest, current is stillfocused in the vicinity of the plates 2420, meaning that there is ahigher concentration of current at the steel plates 2420. However, nocurrent pathways are seen in the areas where the non-conductiveintermediate granular material 2427 resides. The current must now goaround the non-conductive material 2427, effectively mitigating thehighly focused current of the first simulation.

Finally, FIG. 28 demonstrates the resulting heating distribution in thefracture 2410 from the simulation. The units of the map 2400 aremeasured in Watts/ft². A gray-scale is provided indicating values from0.0-0.2 up to 3.0-3.2 Watts/ft². As can be seen, the heat distributionin the map 2400 in FIG. 28 shows a total heat input of 1,000 Watts. Noareas of intense heat generation around the plates 2420L, 2420R areseen. Indeed, heat generation is essentially zero in the area where thenon-conductive granular material 2427 is emplaced. However, the heatingdistribution is not nearly as uniform as the heating distribution seenin FIG. 23 for the second simulation. For this reason, the use of higherconductivity material (as in the second simulation) rather thannon-conductive material (as in the third simulation) is consideredpreferable.

The above-described processes may be of merit in connection with therecovery of hydrocarbons in the Piceance Basin of Colorado. Some haveestimated that in some oil shale deposits of the Western United States,up to 1 million barrels of oil may be recoverable per surface acre. Onestudy has estimated the oil shale resource within the nahcolite-bearingportions of the oil shale formations of the Piceance Basin to be 400billion barrels of shale oil in place. Overall, up to 1 trillion barrelsof shale oil may exist in the Piceance Basin alone.

Certain features of the present invention are described in terms of aset of numerical upper limits and a set of numerical lower limits. Itshould be appreciated that ranges formed by any combination of theselimits are within the scope of the invention unless otherwise indicated.Although some of the dependent claims have single dependencies inaccordance with U.S. practice, each of the features in any of suchdependent claims can be combined with each of the features of one ormore of the other dependent claims dependent upon the same independentclaim or claims.

While it will be apparent that the invention herein described is wellcalculated to achieve the benefits and advantages set forth above, itwill be appreciated that the invention is susceptible to modification,variation and change without departing from the spirit thereof.

1. A method for heating a subsurface formation using electrical resistance heating, comprising: providing two or more wellbores that penetrate an interval of solid organic-rich rock within the subsurface formation; establishing at least one fracture in the organic-rich rock from at least one of the two or more wellbores; providing electrically conductive material in the at least one fracture so as to provide electrical communication between the two or more wellbores, the electrically conductive material comprising (i) first portions placed in contact with each of the two or more wellbores and having a first bulk resistivity, and (ii) a second electrically conductive portion intermediate the two or more wellbores and having a second bulk resistivity; and passing electric current through the at least one fracture such that resistive heat is generated within the electrically conductive material sufficient to pyrolyze at least a portion of the organic-rich rock into hydrocarbon fluids, wherein the generated heat is lower within the first portions of the electrically conductive material than in the second portion of the electrically conductive material.
 2. The method of claim 1, wherein the organic-rich rock comprises oil shale.
 3. The method of claim 2, wherein: each of the two or more wellbores is completed substantially vertically; and the at least one fracture is substantially horizontal.
 4. The method of claim 2, wherein: each of the two or more wellbores is completed substantially horizontally; and the at least one fracture is substantially vertical.
 5. The method of claim 2, wherein the electrically conductive material is a granular material that serves as a proppant.
 6. The method of claim 2, wherein the first portions of the electrically conductive material comprise granular metal, metal coated particles, coke, graphite, or combinations thereof.
 7. The method of claim 2, wherein the second portion of the electrically conductive material comprises granular metal, metal coated particles, coke, graphite, or combinations thereof.
 8. The method of claim 2, wherein the resistivity of the material comprising the second portion of the electrically conductive material is about 10 to 100 times greater than the resistivity of the material comprising the first portions of the electrically conductive material.
 9. The method of claim 2, wherein: the first portions of the electrically conductive material are substantially non-conductive; and the second portion of the electrically conductive material contacts at least a portion of each of the two or more wellbores.
 10. The method of claim 9, wherein the first portions of the electrically conductive material comprise silica, quartz, cement chips, sandstone, or combinations thereof.
 11. The method of claim 2, wherein the resistivity of the first portions of the electrically conductive material is about 0.005 Ohm-Meters.
 12. The method of claim 2, wherein the resistivity of the first portions of the electrically conductive material is between about 0.00001 Ohm-Meters and 0.00005 Ohm-Meters.
 13. The method of claim 2, wherein the resistivity of the first portions of the electrically conductive material approaches infinity.
 14. The method of claim 2, wherein the at least one fracture is formed hydraulically.
 15. The method of claim 2, further comprising: continuing to pass electrical current through the first and second portions of electrically conductive material so as to cause pyrolysis of oil shale into hydrocarbon fluids; and producing hydrocarbon fluids from the subsurface formation to a surface processing facility.
 16. A method for heating a subsurface formation using electrical resistance heating, comprising: creating at least one passage in the subsurface formation between a first wellbore located at least partially within the subsurface formation and a second wellbore also located at least partially within the subsurface formation; providing an electrically conductive material into the at least one passage to form an electrical connection, the electrical connection providing electrical communication between the first wellbore and the second wellbore; providing a first electrically conductive member in the first wellbore so that the first electrically conductive member is in electrical communication with the electrical connection; providing a second electrically conductive member in the second wellbore, so that the second electrically conductive member is in electrical communication with the electrical connection, thereby forming an electrically conductive flow path comprised at least of the first electrically conductive member, the electrical connection and the second electrically conductive member; and establishing an electrical current through the electrically conductive flow path, thereby generating heat within the electrically conductive flow path due to electrical resistive heating, with at least a portion of the generated heat thermally conducting into the subsurface formation, and wherein the generated heat is comprised of first heat generated in proximity to the first electrically conductive member and the second electrically conductive member, and second heat generated from the electrically conductive granular material intermediate the first electrically conductive member and the second electrically conductive member, with the first heat being less than the second heat.
 17. The method of claim 16, wherein the subsurface formation is an organic-rich rock formation.
 18. The method of claim 17, wherein the subsurface formation contains heavy hydrocarbons.
 19. The method of claim 17, wherein the subsurface formation is an oil shale formation.
 20. The method of claim 17, wherein: the electrically conductive material is a granular material; and the electrical connection is a granular electrical connection.
 21. The method of claim 20, wherein the generated heat causes pyrolysis of solid hydrocarbons within at least a portion of the subsurface formation.
 22. The method of claim 21, wherein: the electrically conductive granular material comprises (i) first portions in immediate proximity to the first electrically conductive member and the second electrically conductive member, respectively, and (ii) a second portion intermediate the first portions around the first and second electrically conductive members; and a resistivity of the first portions is different than a resistivity of the second portion.
 23. The method of claim 22, wherein the first portions of the electrically conductive granular material have a sufficiently low electrical resistivity so as to provide electrical conduction without substantial heat generation.
 24. The method of claim 22, wherein the first portions of the electrically conductive granular material comprises granular metal, metal coated particles, coke, graphite, or combinations thereof.
 25. The method of claim 22, wherein the second portion of the electrically conductive granular material comprises granular metal, metal coated particles, coke, graphite, or combinations thereof.
 26. The method of claim 22, wherein the resistivity of the material comprising the second portion of the electrically conductive granular material is about 10 to 100 times greater than the resistivity of the material comprising the first portions of the electrically conductive granular material.
 27. The method of claim 22, wherein the first portions of the electrically conductive granular material comprises less than or equal to 50 percent by dry weight of cement and 50 percent or more by dry weight of graphite.
 28. The method of claim 22, wherein the first portions of the electrically conductive granular material comprises between 50 to 75 percent of granular metal, metal coated particles, coke, graphite, or combinations thereof.
 29. The method of claim 22, wherein: the first portions of the electrically conductive granular material are substantially non-conductive; and the second portion of the electrically conductive granular material contacts at least a portion of each of the first and second electrically conductive members.
 30. The method of claim 29, wherein the first portions of the electrically conductive granular material comprise silica, quartz, cement chips, sandstone, or combinations thereof.
 31. The method of claim 26, wherein the resistivity of the first portions of the electrically conductive granular material is about 0.005 Ohm-meters.
 32. The method of claim 26, wherein the resistivity of the first portions of the electrically conductive material approaches infinity.
 33. The method of claim 22, wherein: the first wellbore and the second wellbore is each completed substantially vertically; and the passage in the subsurface formation comprises a substantially vertically fracture.
 34. The method of claim 26, wherein: the first wellbore and the second wellbore is each completed substantially horizontally; and the at least one passage in the subsurface formation comprises a first substantially vertical fracture.
 35. The method of claim 33, further comprising: providing a third electrically conductive member in a third wellbore, such that the third electrically conductive member is also in electrical communication with the electrical connection and is part of the electrically conductive flow path; wherein the third wellbore is completed substantially horizontally; the at least one passage in the subsurface formation comprises a second substantially vertical fracture; and the second wellbore intersects both the first fracture and the second fracture.
 36. The method of claim 22, wherein the material comprising at least a portion of the first electrically conductive member, the second electrically conductive member, or both has an electrical resistivity of less than 0.0005 Ohm-meters.
 37. The method of claim 22, further comprising: continuing to pass an electrical current through the electrical connection until the subsurface formation immediately adjacent the electrically conductive flow path reaches a selected temperature; and reducing an amount of current through the electrical connection.
 38. A system for in situ heating of a subsurface formation using electrical resistance heating, comprising: a plurality of wellbores that penetrate an interval of solid organic-rich rock within the subsurface formation; at least one fracture in the organic-rich rock established from at least one of the wellbores, wherein the at least one fracture comprises electrically conductive material to provide electrical communication between at least two of the wellbores, the electrically conductive material including (i) first portions placed in contact with at least two wellbores and having a first bulk resistivity, and (ii) a second electrically conductive portion intermediate the at least two wellbores and having a second bulk resistivity; and at least one electrical conductor operatively connected to the first portions of the electrically conductive material in each of the at least two wellbores, the at least one electrical conductor being configured to pass electric current through the at least one fracture such that resistive heat is generated within the electrically conductive material sufficient to pyrolyze at least a portion of the organic-rich rock into hydrocarbon fluids, and wherein the generated heat is lower within the first portions of the electrically conductive material than in the second portion of the electrically conductive material.
 39. The system of claim 38, wherein: each of the two or more wellbores is completed substantially vertically; and the at least one fracture is substantially horizontal.
 40. The system of claim 38, wherein: each of the two or more wellbores is completed substantially horizontally; and the at least one fracture is substantially vertical.
 41. The system of claim 38, wherein the electrically conductive material is a granular material that serves as a proppant.
 42. The system of claim 38, wherein the first portions of the electrically conductive material comprise granular metal, metal coated particles, coke, graphite, or combinations thereof.
 43. The system of claim 38, wherein the second portion of the electrically conductive material comprises granular metal, metal coated particles, coke, graphite, or combinations thereof.
 44. The system of claim 38, wherein the resistivity of the material comprising the second portion of the electrically conductive material is about 10 to 100 times greater than the resistivity of the material comprising the first portions of the electrically conductive material.
 45. The system of claim 38, wherein: the first portions of the electrically conductive material are substantially non-conductive; and the second portion of the electrically conductive material contacts at least a portion of each of the two or more wellbores.
 46. The system of claim 45, wherein the first portions of the electrically conductive material comprise silica, quartz, cement chips, sandstone, or combinations thereof.
 47. The system of claim 38, wherein the resistivity of the first portions of the electrically conductive material is about 0.005 Ohm-Meters.
 48. The system of claim 38, wherein the resistivity of the first portions of the electrically conductive material is between about 0.00001 Ohm-Meters and 0.00005 Ohm-Meters.
 49. The system of claim 38, wherein the resistivity of the first portions of the electrically conductive material approaches infinity.
 50. The system of claim 38, wherein the at least one fracture is formed hydraulically.
 51. The system of claim 38, further comprising at least one production well for producing hydrocarbon fluids from the subsurface formation. 